<PAGE>

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                      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,           Commission file number 1-10982
2000

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

                Texas                                    75-6415930
   (State or other jurisdiction of             (I.R.S. Employer Identification
   incorporation or organization)                           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:

<TABLE>
<CAPTION>
            Title of each class             Name of each exchange on which registered
            -------------------             -----------------------------------------
  <S>                                       <C>
        Units of Beneficial Interest                 New York Stock Exchange
</TABLE>

       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, 2001, 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, 2001) held by non-
affiliates of the registrant on that date was approximately $77.3 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:

                  2000 Annual Report to Unitholders--Part II

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<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 Cross Timbers Oil Company, 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 Cross Timbers Oil 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 Cross Timbers Oil received 6,000,000 units of beneficial
interest of the trust. Predecessors of Cross Timbers Oil distributed units to
their owners in February 1991 and November 1992, and in February 1992, sold
units in the trusts initial public offering. Units are listed and traded on
the New York Stock Exchange under the symbol "CRT." During 1996 and 1997,
Cross Timbers Oil's Board of Directors authorized Cross Timbers Oil to
purchase two million units. As of March 1, 2001, Cross Timbers Oil owned
1,360,000 units, or 22.7%, of the outstanding units.

  In June 1998 the trust and Cross Timbers Oil filed a registration statement
with the Securities and Exchange Commission to sell the 1,360,000 units held
by Cross Timbers Oil. As Cross Timbers Oil 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. The trust did not participate in Cross
Timbers Oil'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 royalty
income from the net profits interests on the last business day of each month.
Royalty income is determined by Cross Timbers Oil 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, 2000 was $22,570. 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 royalty income
in excess of the amount due, the trust is not obligated to return such
overpayment, but royalty income payable to the trust for the next month will
be reduced by the overpayment, plus interest at the prime rate.

                                       1
<PAGE>

  Cross Timbers Oil does not operate or control any of the underlying
properties. However, Cross Timbers Oil operates working interests from which
approximately 20 overriding royalty interests in the San Juan Basin were
conveyed. Cross Timbers Oil acquired these working interests in December 1997
and became operator. As a working interest owner, Cross Timbers Oil can
generally decline participation in any operation and allow consenting parties
to conduct such operations, as provided under the operating agreements. Cross
Timbers Oil 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 Cross Timbers Oil.

  To the extent it has the right to do so, Cross Timbers Oil 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.

  Royalty 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) royalty 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 royalty income from the net profits
interests, to pay all trust expenses and pay the monthly distribution amount
to unitholders. The trustee's powers are specified by the terms of the
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 64% of the royalty income received by the trust during 2000,
as well as 86% of the estimated proved reserves of the net profits interests
at December 31, 2000 (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.

                                       2
<PAGE>

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 the trust's gross revenue is less than
$1,000,000 for two successive years.

  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 Cross Timbers Oil. Cross
Timbers Oil 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 28.3 Bcf at December 31,
2000, or approximately 81% of the trust's total gas reserves at that date.
Cross Timbers Oil 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, Mesa Verde and Pictured
Cliffs formations.

  Approximately 28% of the trust's 2000 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."

  Most of the trust's San Juan Basin conventional, or non-coal seam,
production is from the Mesa Verde formation, which has been approved for
increased density drilling. Cross Timbers Oil believes that operators will
further develop the Mesa Verde formation underlying the net profits interests,
and such future development could significantly impact underlying gas sales
volumes. However, minimal drilling is expected in 2001 because of
environmental concerns delaying 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 Exxon Company,
U.S.A. 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
                                                                                    Cross Timbers Oil
                                                                                    -----------------
                                                                                    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   Mobil Producing Texas and New Mexico, Inc.    3.2%    2.1%
Penwell                  Ector/Texas     Texaco Exploration and Production, Inc.       5.2%    4.6%
Sharon Ridge Canyon      Borden/Texas    Exxon Company, U.S.A.                         4.3%    2.8%
Hewitt                   Carter/Oklahoma Exxon Company, U.S.A.                        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, 2000, there were 1,494 gross (68.3
net) productive oil wells, 1,002 gross (42.9 net) injection wells and no wells
in process of drilling on these properties. During 2000, 12 gross (0.2 net)
wells were drilled and during 1999, 8 gross (0.1 net) producing wells were
drilled. No wells were drilled during 1998.

Oil and Gas Production

  Trust production is recognized in the period royalty income is received,
which is the month following receipt by Cross Timbers Oil, 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, 2000 were as follows:

<TABLE>
<CAPTION>
                             90% Net Profits Interests     75% Net Profits Interests               Total
                          -------------------------------- -------------------------- --------------------------------
                             2000       1999       1998      2000     1999     1998      2000       1999       1998
                          ---------- ---------- ---------- -------- -------- -------- ---------- ---------- ----------
<S>                       <C>        <C>        <C>        <C>      <C>      <C>      <C>        <C>        <C>
Production
Underlying Properties
 Oil--Sales (Bbls)......      86,970     92,650    100,592  257,153  255,959  291,777    344,123    348,609    392,369
 Average per day
  (Bbls)................         238        254        276      702      701      799        940        955      1,075
 Gas--Sales (Mcf).......   2,964,687  3,548,594  3,398,203  115,914   94,429  103,890  3,080,601  3,643,023  3,502,093
 Average per day (Mcf)..       8,100      9,722      9,310      317      259      285      8,417      9,981      9,595
Net profits interests
 Oil--Sales (Bbls)......      76,959     77,783     83,856   86,260   19,894   20,918    163,219     97,677    104,774
 Average per day
  (Bbls)................         210        213        230      236       55       57        446        268        287
 Gas--Sales (Mcf).......   2,659,139  3,152,693  3,010,809   30,120   10,249    7,857  2,689,259  3,162,942  3,018,666
 Average per day (Mcf)..       7,266      8,638      8,249       82       28       21      7,348      8,666      8,270
Average Sales Price
 Oil (per Bbl)..........  $    26.41 $    14.54 $    14.04 $  27.85 $  15.01 $  13.18 $    27.49 $    14.88 $    13.40
 Gas (per Mcf)..........  $     3.36 $     2.01 $     2.05 $   2.28 $   1.35 $   1.34 $     3.32 $     1.99 $     2.03
</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. Cross Timbers Oil 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
Cross Timbers Oil as a royalty owner, or to the trust.

Oil and Natural Gas Reserves

  General

  The following are definitions adopted by the Securities and Exchange
Commission and the Financial Accounting Standards Board which are applicable
to terms used in the following discussion of oil and gas reserves:

    Proved reserves--Estimated quantities of crude oil, natural gas and
  natural gas liquids which, upon analysis of geologic and engineering data,
  appear with reasonable certainty to be recoverable in the future from known
  oil and gas reservoirs under existing economic and operating conditions.

    Proved developed reserves--Proved reserves which can be expected to be
  recovered through existing wells with existing equipment and operating
  methods.

    Proved undeveloped reserves--Proved reserves which are expected to be
  recovered from new wells on undrilled acreage, or from existing wells where
  a relatively major expenditure is required.

    Estimated future net revenues--Also referred to herein as "estimated
  future net cash flows." Computational result of applying current prices of
  oil and gas (with consideration of price changes only to the extent
  provided by existing contractual arrangements) to estimated future
  production from proved oil and gas reserves as of the date of the latest
  balance sheet presented, less estimated future expenditures (based on
  current costs) to be incurred in developing and producing the proved
  reserves. Estimated future net revenues do not include the effects of the
  coal seam tax credit, since the trust is not a taxable entity and the
  credit inures directly to the benefit of the unitholder (see "Discounted
  Present Value of the Coal Seam Tax Credit" below).

    Present value of estimated future net revenues--Also referred to herein
  as "standardized measure of discounted future net cash flows" or
  "standardized measure." Computational result of discounting estimated
  future net revenues at a rate of 10% annually.

  Miller and Lents, Ltd., independent petroleum engineers, has estimated oil
and gas reserves attributable to the underlying properties and net profits
interests as of December 31, 2000, 1999, 1998 and 1997. 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 Cross Timbers Oil 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 interest 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

                                       5
<PAGE>

4-6 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 $23.75 per Bbl in 2000,
$22.75 per Bbl in 1999, $9.50 per Bbl in 1998 and $15.50 per Bbl in 1997. The
year-end weighted average realized gas prices used to determine the
standardized measure were $9.48 per Mcf in 2000, $2.19 per Mcf in 1999, $1.88
per Mcf in 1998 and $1.76 per Mcf in 1997.

  Proved Reserves

  The following table reconciles the change in proved reserves attributable to
the net profits interests and underlying properties from December 31, 1997
through December 31, 2000:

<TABLE>
<CAPTION>
                                      Net Profits Interests
                         ----------------------------------------------------
                                              75% Net
                         90% Net Profits      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,
 1997................... 731.5   37,886.2    964.7   355.6  1,696.2  38,241.8   4,418.3  44,075.4
 Extensions, discoveries
  and other additions...   3.6       95.7      -0-     -0-      3.6      95.7       4.1     265.6
 Revisions of prior
  estimates.............  25.3    1,482.1   (696.7) (282.4)  (671.4)  1,199.7  (1,620.1)    894.5
 Production............. (83.9)  (3,010.8)   (20.9)   (7.9)  (104.8) (3,018.7)   (392.4) (3,502.1)
                         -----   --------  -------  ------  -------  --------  --------  --------
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
                         =====   ========  =======  ======  =======  ========  ========  ========
</TABLE>

  During 2000, 1999 and 1998, upward revisions of prior estimates of the 90%
net profits interests' proved gas reserves were primarily because of lower
than anticipated production declines. Revisions of prior estimates of the 75%
net profits interests' proved reserves and the underlying properties' proved
oil reserves in each of these years were primarily the result of changes in
the year-end oil prices used in estimating proved reserves. See "General"
above.

                                       6
<PAGE>

  Proved Developed Reserves

  The following are estimated quantities of proved developed oil and gas
reserves attributable to the net profits interests and underlying properties
as of December 31, 1997 and each following year-end through December 31, 2000:

<TABLE>
<CAPTION>
                                     Net Profits Interests
                         ----------------------------------------------
                                            75% Net
                         90% Net Profits    Profits                        Underlying
                            Interests      Interests        Total          Properties
                         --------------- ------------- ---------------- ----------------
                          Oil     Gas      Oil    Gas    Oil     Gas      Oil     Gas
                         (Bbls)  (Mcf)   (Bbls)  (Mcf) (Bbls)   (Mcf)   (Bbls)   (Mcf)
(in thousands)           ------ -------- ------- ----- ------- -------- ------- --------
<S>                      <C>    <C>      <C>     <C>   <C>     <C>      <C>     <C>
December 31, 1997....... 727.9  35,947.4   908.6 346.8 1,636.5 36,294.2 4,231.6 43,576.1
                         =====  ======== ======= ===== ======= ======== ======= ========
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
                         =====  ======== ======= ===== ======= ======== ======= ========
</TABLE>

  Standardized Measure of Discounted Future Net Cash Flows from Proved
Reserves

  The following are summary calculations of the standardized measure of
discounted future net cash flows for the net profits interests and underlying
properties as of December 31, 2000, 1999 and 1998:


<TABLE>
<CAPTION>
                          90% Net Profits Interests     75% Net Profits Interests               Total
                         -----------------------------  ---------------------------  ------------------------------
                                December 31,                  December 31,                   December 31,
                         -----------------------------  ---------------------------  ------------------------------
                           2000       1999      1998      2000      1999     1998      2000       1999       1998
(in thousands)           ---------  --------  --------  --------  --------  -------  ---------  ---------  --------


  Net Profits Interests

<S>                      <C>        <C>       <C>       <C>       <C>       <C>      <C>        <C>        <C>
Future cash inflows..... $ 347,874  $ 97,902  $ 77,207  $ 40,146  $ 36,670  $ 2,582  $ 388,020  $ 134,572  $ 79,789
Future production
 taxes..................   (28,042)   (7,751)   (5,401)   (2,786)   (2,487)    (131)   (30,828)   (10,238)   (5,532)
                         ---------  --------  --------  --------  --------  -------  ---------  ---------  --------
Future net cash flows...   319,832    90,151    71,806    37,360    34,183    2,451    357,192    124,334    74,257
10% discount factor.....  (169,073)  (46,573)  (37,222)  (18,692)  (17,135)  (1,259)  (187,765)   (63,708)  (38,481)
                         ---------  --------  --------  --------  --------  -------  ---------  ---------  --------
Standardized measure.... $ 150,759  $ 43,578  $ 34,584  $ 18,668  $ 17,048  $ 1,192  $ 169,427  $  60,626  $ 35,776
                         =========  ========  ========  ========  ========  =======  =========  =========  ========

  Underlying Properties

Future cash inflows...........................................................       $ 484,675  $ 200,075  $104,659
Future costs:
 Production...................................................................         (78,973)   (52,858)  (20,265)
 Development..................................................................            (520)      (517)     (519)
                                                                                     ---------  ---------  --------
Future net cash flows.........................................................         405,182    146,700    83,875
10% discount factor...........................................................        (212,781)   (74,879)  (43,282)
                                                                                     ---------  ---------  --------
Standardized measure..........................................................       $ 192,401  $  71,821  $ 40,593
                                                                                     =========  =========  ========
</TABLE>


                                       7
<PAGE>

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

  The following reconciles the changes during 2000, 1999 and 1998 in the
standardized measure for the net profits interests. Revisions in each of the
years were primarily related to changes in year-end oil and gas prices.

<TABLE>
<CAPTION>
                             90% Net Profits            75% Net Profits
                                Interests                  Interests                    Total
                         --------------------------  ------------------------  --------------------------
                           2000     1999     1998     2000     1999     1998     2000     1999     1998
                         --------  -------  -------  -------  -------  ------  --------  -------  -------
(in thousands)
<S>                      <C>       <C>      <C>      <C>      <C>      <C>     <C>       <C>      <C>
Standardized measure,
 January 1.............. $ 43,578  $34,584  $35,650  $17,048  $ 1,192  $7,846  $ 60,626  $35,776  $43,496
 Extensions, discoveries
  and other additions...      461      384      155      -0-      -0-     -0-       461      384      155
 Accretion of discount..    3,683    3,078    3,176    1,476      106     698     5,159    3,184    3,874
 Revisions of prior
  estimates, changes in
  price and other.......  112,338   11,864    2,369    2,504   16,109  (7,038)  114,842   27,973   (4,669)
 Royalty income.........   (9,301)  (6,332)  (6,766)  (2,360)    (359)   (314)  (11,661)  (6,691)  (7,080)
                         --------  -------  -------  -------  -------  ------  --------  -------  -------
Standardized measure,
 December 31............ $150,759  $43,578  $34,584  $18,668  $17,048  $1,192  $169,427  $60,626  $35,776
                         ========  =======  =======  =======  =======  ======  ========  =======  =======
</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, 2000, 1999 and 1998. Such estimates are
based on projected coal seam gas production through the year 2002 (after which
date the tax credit will 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 $1.06 per MMBtu at December 31, 2000,
$1.02 per MMBtu at December 31, 1999 and $1.05 per MMBtu at December 31, 1998.
"See Regulation--Coal Seam Tax Credit."

<TABLE>
<CAPTION>
                                                               December 31,
                                                           --------------------
                                                            2000   1999   1998
                                                           ------ ------ ------
   (in thousands)
   <S>                                                     <C>    <C>    <C>
   Undiscounted........................................... $1,225 $1,979 $2,780
                                                           ====== ====== ======
   Discounted present value at 10%........................ $1,120 $1,740 $2,359
                                                           ====== ====== ======
</TABLE>

Certain Provisions Affecting San Juan Basin Royalty Interests

  Certain instruments creating or governing some of the underlying properties
that are royalties and overriding royalties in the San Juan Basin contain
provisions that purportedly either reduce the overriding royalty interest or
convert the royalty or overriding royalty interest into a working interest
when gas production falls below specified levels. Cross Timbers Oil believes
these provisions were included in these instruments because of a federal
regulation that has since been repealed which limited the amount of royalties
and overriding royalties placed on federal leases in the San Juan Basin. No
assurances, however, can be made regarding the effect of these provisions on
the trust. Cross Timbers Oil and other royalty interest owners filed a
lawsuit, later joined by the trust in 1993, to recover revenues suspended by
working interest owners based on their interpretation of these reduction or
conversion provisions. The trust, Cross Timbers Oil and the other royalty
owners settled this lawsuit in 1996, receiving past production due to the
trust and receiving further compensation for an agreement to reduce the trusts
interest in the involved properties.

Reversion Agreement

  Certain of the underlying royalties are subject to a reversion agreement
between Cross Timbers Oil and a third party. The agreement calls for Cross
Timbers Oil to transfer 25% of its interest in those properties to the third
party when amounts received by Cross Timbers Oil 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

                                       8
<PAGE>

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 2000 prices and levels of production, Cross Timbers Oil has
advised the trustee that payout is not projected to occur for more than 13
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 royalty 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 2000 was approximately $1.06 per MMBtu. Such
credit, calculated based on the unitholders 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.

  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 FERCs 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. Cross Timbers
Oil 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. Cross
Timbers Oil has advised the trustee that it does not believe that the ultimate
resolution of these claims will have a material effect on the trust's annual
distribution 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 2000.

                                      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, 2000 is
incorporated herein by reference.

Item 6. Selected Financial Data

<TABLE>
<CAPTION>
                                            Year Ended December 31,
                          -----------------------------------------------------------
                             2000        1999        1998        1997        1996
                          ----------- ----------- ----------- ----------- -----------
<S>                       <C>         <C>         <C>         <C>         <C>
Royalty Income..........  $11,660,510 $ 6,691,336 $ 7,079,632 $10,549,668 $ 8,269,875
Distributable Income....   11,502,114   6,549,803   6,927,338  10,407,250   8,076,964
Distributable Income per
 Unit...................     1.917019    1.091635    1.154555    1.734541    1.346162
Distributions per Unit..     1.917019    1.091635    1.154555    1.734541    1.346162
Total Assets at Year-
 End....................   31,806,794  33,919,338  36,554,480  38,767,918  42,716,284
</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, 2000 on pages 6
through 8 of the trust's Annual Report to Unitholders for the year ended
December 31, 2000 is incorporated herein by reference.

  Forward-Looking Statements

  Certain information included in this annual report and other materials 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 Cross Timbers Oil or the trustee) contain forward-looking
statements within the meaning of Section 21E of the Securities and 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,
production levels, litigation, regulatory matters and competition. Such
forward-looking statements are based on Cross Timbers Oil'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

                                      11
<PAGE>

into any investments other than investing cash on hand in specific short-term
cash investments. Therefore, the trust cannot hold any derivative financial
instruments. As a result of the limited nature of the trust's borrowing and
investing activities, the trust is not subject to any material interest rate
market risk. Additionally, any gains or losses from any hedging activities
conducted by Cross Timbers Oil 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, 2001, appearing on
pages 9 through 12 of the trust's Annual Report to Unitholders for the year
ended December 31, 2000 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, 2000.

                                      12
<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 1998 through
2000 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  2000     $5,830
                                     1999      3,346
                                     1998      3,540
</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) trustees 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, 2001 information with respect to each person known
to the trustee to beneficially own more than 5% of the outstanding units of
the trust:

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

(1) Cross Timbers Oil has the sole power to vote and dispose of 1,360,000
    units.

  (b) Security Ownership of Management. The trust has no directors or
executive officers. As of March 1, 2001, Bank of America, N.A. owned, in
various fiduciary capacities, 116,596 units with a shared right to vote 27,596
of these units and no right to vote 89,000 of these units. Bank of America,
N.A. disclaims any beneficial interests in these units. The number of units
reflected in this paragraph includes units held by all branches of Bank of
America, N.A.

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

Item 13. Certain Relationships and Related Transactions

  In computing royalty income paid to the trust for the 75% net profits
interests, Cross Timbers Oil deducts an overhead charge as reimbursement for
costs associated with monitoring these interests. This charge at December 31,
2000 was $22,570 per month, or $270,840 annually (net to the trust of $16,928
per month or $203,130 annually), and is subject to annual adjustment based on
an oil and gas industry index.

  During 2000, Bank of America, N.A. received $6,938 for oil and gas
consulting services performed on behalf of the trust. See Item 11 for the
remuneration received by the trustee from 1998 through 2000 and Item 12(b) for
information concerning units owned by the trustee, Bank of America, N.A., in
various fiduciary capacities.

                                      13
<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, 2000
    and 1999
    Statements of Distributable Income for the years ended December 31,
    2000, 1999 and 1998
    Statements of Changes in Trust Corpus for the years ended December 31,
    2000, 1999 and 1998
    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) 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, 2000.

    (23.1)  Consent of Arthur Andersen LLP

    (23.2)  Consent of Miller and Lents, Ltd.

      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, 2000,
there were no reports filed on Form 8-K by the trust with the Securities and
Exchange Commission.

                                      14
<PAGE>

                                  SIGNATURES

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

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

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

                                          CROSS TIMBERS OIL COMPANY

Date: March 30, 2001                      By        LOUIS G. BALDWIN
                                            ___________________________________
                                                    Louis G. Baldwin
                                              Executive Vice President and
                                                 Chief Financial Officer

              (The trust has no directors or executive officers.)

                                      15