<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 1-10476
2000

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

                Texas                                    58-6379215
                                                      (I.R.S. Employer
   (State or other jurisdiction of                   Identification No.)
   incorporation or organization)

        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) 228-5083

          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, 2001, there were 40,000,000 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 $258.2 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

  Hugoton Royalty Trust is an express trust created under the laws of Texas
pursuant to the Hugoton Royalty Trust Indenture entered into on December 1,
1998 between Cross Timbers Oil Company, as grantor, and NationsBank, N.A., as
trustee. Bank of America, N.A., successor to NationsBank, N.A., is now the
trustee of the trust. The principal office of the trust is located at 901 Main
Street, Dallas, Texas 75202 (telephone number 877-228-5083).

  Effective December 1, 1998, Cross Timbers conveyed to the trust 80% defined
net profits interests in certain predominantly natural gas producing working
interest properties in Kansas, Oklahoma and Wyoming under three separate
conveyances. In exchange for these net profits interest conveyances to the
trust, 40 million units of beneficial interest were issued to Cross Timbers.
In April and May 1999, Cross Timbers sold a total of 17 million units in the
trust's initial public offering. In 1999 and 2000, Cross Timbers also sold 1.3
million trust units to certain of its officers. The trust did not receive any
proceeds from these sales of trust units. As of March 1, 2001, Cross Timbers
owned 21,705,893 units in the trust. Units are listed and traded on the New
York Stock Exchange under the symbol "HGT."

  The net profits interests entitle the trust to receive 80% of net proceeds
from the sale of oil and gas from the underlying properties. Each month Cross
Timbers determines the amount of cash received from the sale of production and
deducts property and production taxes, development and production costs and
overhead. For trust distributions declared through March 2000, net proceeds
from the sale of gas related to those distributions were contractually
required to be computed differently. Net proceeds for this period were
computed monthly based on the greater of either a realized price of $2.00 per
Mcf or the actual price received by Cross Timbers for natural gas sold.

  Net proceeds payable to the trust depend upon production quantities, sales
prices of oil and gas and costs to develop and produce the oil and gas. If at
any time 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 costs from one conveyance cannot be used
to reduce net proceeds from another 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.

  To the extent it has the right to do so, Cross Timbers 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. See Item 2., "Pricing and Sales Information."

  Royalty income received by the trust on or before the last business day of
the month is related to net proceeds received by Cross Timbers in the
preceding month, and generally represents receipts attributable to oil and gas
production two months prior. The amount to be distributed to unitholders each
month by the trustee is determined by:

   Adding--
    (1) royalty income received,
    (2) interest income and any other cash receipts and
    (3) cash available as a result of reduction of cash reserves, then

   Subtracting the sum of--
    (1) liabilities paid and
    (2) the reduction in cash available related to establishment of or
increase in any cash reserve.

                                       1
<PAGE>

  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 trust
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 90% of the royalty income received by the trust during 2000,
as well as 98% 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 generally 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 assets, with the exception of certain short-term
investments as specified under Item 1. The trustee may sell or otherwise
dispose of all or any part of the net profits interests if approved by at
least 80% of the unitholders, or upon termination of the trust. Otherwise, the
trust may only sell up to 1% of the value of the net profits interests in any
calendar year, pursuant to notice from Cross Timbers of its desire to sell the
related underlying properties. Any such sale must be for cash with the
proceeds promptly distributed to the unitholders. The underlying properties
are predominantly natural gas producing leases located in the states of
Kansas, Oklahoma and Wyoming. The principal productive areas are the Hugoton
area, Anadarko Basin and Green River Basin.

   Hugoton Area

  Natural gas was discovered in the Hugoton area in 1922. With an estimated
five million productive acres covering parts of Texas, Oklahoma and Kansas,
the Hugoton area is the largest natural gas producing area in North America.
More than 64 trillion cubic feet of natural gas have been produced from the
Hugoton area.

  The Permian-aged Chase formation is the major productive formation in the
Hugoton area, ranging in depth from 2,700 to 2,900 feet. Additional productive
formations in the Hugoton area include the Council Grove between 2,950 and
3,400 feet, the Morrow between 6,000 and 6,300 feet, the Chester between 6,350
and 6,700 feet and the St. Louis between 7,500 and 8,000 feet.

  Sales volumes from the underlying properties in the Hugoton area averaged
approximately 32,400 Mcf of natural gas per day and 80 Bbls of oil per day.

  Cross Timbers delivers most of its Hugoton natural gas production to a
gathering and processing system operated by a subsidiary. This system collects
approximately 75% of its throughput from underlying properties, which, in
recent months, has been approximately 24,000 Mcf per day from 270 wells. The
gathering subsidiary purchases the gas from Cross Timbers at the wellhead,
gathers and transports the gas to its plant, and treats and processes the gas
at the plant. The gathering subsidiary pays Cross Timbers for wellhead volumes
at a price of 80% to 85% of the residue price received upon sale to Cross
Timbers' marketing affiliate. Under long-term contracts, the gathering
subsidiary sells residue volumes to Cross Timbers' marketing affiliate at a
price equal to

                                       2
<PAGE>

the average price of several published indices and is reduced by any pipeline
access fees incurred by the marketing affiliate, but is not reduced by any
marketing fees. Pipeline access fees currently are approximately $0.02 per
Mcf.

  Other Hugoton natural gas production is delivered under a third party
contract. Under the contract, Cross Timbers receives 74.5% of the net proceeds
received from the sale of the residue gas and liquids.

  In the Hugoton area, Cross Timbers' development plans include:

  .  additional compression to lower line pressures;

  .  pumping unit installations;

  .  opening new producing zones of existing wells;

  .  drilling additional wells; and

  .  drilling deeper in existing wells to new producing zones.

  Most of the production from the underlying properties is from the Chase
formation. In June 1999, Oklahoma regulations were amended to allow increased
drilling density in the Oklahoma panhandle where Cross Timbers has
approximately 200 infill well locations on the underlying properties. Cross
Timbers also plans to develop other formations, including the Council Grove,
Chester, Morrow and St. Louis formations that underlie the 79,500 net acres
held by production by the Chase formation wells. Cross Timbers has
participated in 3-D seismic shoots covering 30,000 acres of Cross Timbers' net
acreage position beneath the Chase formation. Test wells were drilled to
delineate the Council Grove formation in 1999 and 2000.

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

   Anadarko Basin

  Oil and natural gas were discovered in the Anadarko Basin of western
Oklahoma in 1945. Daily sales volumes from the underlying properties in the
Anadarko Basin averaged 42,100 Mcf and 950 barrels in 2000. Cross Timbers is
one of the largest producers in the Ringwood, Northwest Okeene and Cheyenne
Valley fields in Major County, the principal producing region of the
underlying properties in the Anadarko Basin.

  The fields in the Major County area are characterized by oil and natural gas
production from a variety of structural and stratigraphic traps. Productive
zones range from 6,500 to 9,400 feet and include the Oswego, Red Fork, Inola,
Chester, Manning, Mississippian, Hunton and Arbuckle formations.

  A gathering subsidiary of Cross Timbers operates a 300-mile gathering system
and pipeline in the Major County area. The gathering subsidiary and a third-
party processor purchase natural gas produced at the wellhead from Cross
Timbers and other producers in the area under life-of-production contracts.
The gathering subsidiary gathers and transports the gas to a third-party
processor, which processes the gas and pays Cross Timbers and other producers
for at least 50% of the liquids processed. After the gas is processed, the
gathering subsidiary transports the gas via a 26-mile pipeline to a connection
with other pipelines. The gathering subsidiary sells the residue gas to the
marketing subsidiary of Cross Timbers based upon the average price of several
published indices. The gathering subsidiary pays this price to Cross Timbers
less a compression and gathering fee of $0.317 per Mcf of residue gas. This
gathering fee was previously approved by the Federal Energy Regulatory
Commission when the gathering subsidiary was regulated. During 2000, the
gathering system collected approximately 18,000 Mcf per day from over 400
wells, 70% of which Cross Timbers operates. Estimated capacity of the
gathering system is 40,000 Mcf per day. The gathering subsidiary also provides
contract operating services to properties in Woodward County, collecting
approximately 161,000 Mcf per month from 34 wells, for a historical average
fee of approximately $0.125 per Mcf.

                                       3
<PAGE>

  Cross Timbers also sells natural gas to its marketing subsidiary, which then
sells the gas to third parties. The price paid to Cross Timbers is based upon
the average price of several published indices, but does not include a
deduction for any marketing fees. The price paid by the marketing affiliate
includes a deduction for any transportation fees charged by the third party.

  Cross Timbers plans to develop the Major County area primarily through:

  .  mechanical stimulation of existing wells;

  .  opening new producing zones in existing wells;

  .  deepening existing wells to new producing zones; and

  .  drilling additional wells.

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

   Green River Basin

  The Green River Basin is located in southwestern Wyoming. Natural gas was
discovered in the Fontenelle field of the Green River Basin in the early
1970s. The producing reservoirs are the Cretaceous-aged Frontier and Dakota
sandstones at depths ranging from 7,500 to 10,000 feet. Daily sales volumes
from the underlying properties in the Fontenelle field averaged 26,200 Mcf of
natural gas and 60 Bbls of oil in 2000.

  Cross Timbers markets the natural gas produced from the Fontenelle Unit and
nearby properties under three different marketing arrangements. Under the
agreement covering 70% of the gas sold, Cross Timbers compresses the gas on
the lease, transports it off the lease and compresses the gas again prior to
entry into the gas plant pipeline. The pipeline transports the gas 35 miles to
the gas plant, where the gas is processed, then redelivered to Cross Timbers
and sold to Cross Timbers' marketing subsidiary. The owner of the gas plant
and related pipeline charges Cross Timbers for operational fuel and
processing. In 2000, the fuel charge was 0.025% of the volumes produced and
the processing fee was $0.05 per MMBtu. The marketing subsidiary then sells
the residue gas to third parties based upon a spot sales price and pays the
net sales proceeds to Cross Timbers. The marketing subsidiary does not receive
a marketing fee. The gas not sold under the above arrangement is sold either
under a similar arrangement where the fee is $0.145 per MMBtu, or under a
contract where Cross Timbers directly sells the gas to a third party on the
lease at an adjusted index price. Condensate is sold at the lease to an
independent third party at market rates.

  During 1997, Cross Timbers installed additional pipeline compression to
lower overall field operating pressures and improve overall field performance.
Cross Timbers also completed an interconnect to another pipeline in the
southeastern part of the Fontenelle field that added an additional market for
natural gas.

  Potential development activities for the fields in this area include:

  .  additional compression to lower line pressures,

  .  opening new producing zones of existing wells,

  .  deepening existing wells to new producing zones, and

  .  drilling additional wells.

  Cross Timbers drilled five gross (4.9 net) wells in the Fontenelle Unit in
2000, all of which were successfully completed. Cross Timbers plans to drill
up to ten wells and perform up to seven workovers in the Green River Basin
during 2001.

                                       4
<PAGE>

Producing Acreage and Well Counts

  For the following data, "gross" refers to the total wells or acres on the
underlying properties in which Cross Timbers owns a working interest and "net"
refers to gross wells or acres multiplied by the percentage working interest
owned by Cross Timbers. Although many of Cross Timbers' wells produce both oil
and gas, a well is categorized as an oil well or a gas well based upon the
ratio of oil to natural gas production.

  The underlying properties are interests in developed properties located
primarily in gas producing regions of Kansas, Oklahoma and Wyoming. The
following is a summary of the approximate producing acreage of the underlying
properties at December 31, 2000. Undeveloped acreage is not significant.

<TABLE>
<CAPTION>
                                                                  Gross    Net
                                                                 ------- -------
     <S>                                                         <C>     <C>
     Hugoton Area............................................... 217,590 200,390
     Anadarko Basin............................................. 152,042 113,946
     Green River Basin..........................................  42,654  28,841
                                                                 ------- -------
     Total...................................................... 412,286 343,177
                                                                 ======= =======
</TABLE>

  The following is a summary of the producing wells on the underlying
properties as of December 31, 2000:

<TABLE>
<CAPTION>
                                         Operated    Non-Operated
                                           Wells        Wells          Total
                                       ------------- ------------- -------------
                                       Gross   Net   Gross   Net   Gross   Net
                                       ----- ------- ------------- ----- -------
     <S>                               <C>   <C>     <C>    <C>    <C>   <C>
     Gas.............................. 1,049   958.7    257   59.5 1,306 1,018.2
     Oil..............................   131   117.9      7    1.2   138   119.1
                                       ----- -------  ----- ------ ----- -------
     Total............................ 1,180 1,076.6    264   60.7 1,444 1,137.3
                                       ===== =======  ===== ====== ===== =======
</TABLE>

  There were seven (5.2 net) wells in process of drilling at December 31,
2000.

  The following is a summary of the number of wells drilled on the underlying
properties during the year ended December 31, 2000. Unless otherwise
indicated, all wells drilled are developmental.

<TABLE>
<CAPTION>
                                                                      Gross Net
                                                                      ----- ----
     <S>                                                              <C>   <C>
     Completed gas wells (a).........................................   40  31.0
     Completed oil wells (b).........................................    1   0.1
                                                                       ---  ----
     Total...........................................................   41  31.1
                                                                       ===  ====
</TABLE>
--------
(a) Included in completed gas wells are ten gross (1.7 net) wells drilled on
    nonoperated interests.
(b) Completed oil wells were drilled on nonoperated interests.

                                       5
<PAGE>

Oil and Gas Production

  Trust production is recognized in the period royalty income is received,
which is the month following receipt by Cross Timbers, and generally two
months after the time of production. Because of this two-month interval, the
trust's initial accounting year ended December 31, 1999 includes royalty
income related to eleven months of oil and gas sales, or December 1998 (the
trust's initial month) through October 1999 production. Oil and gas production
and average sales prices attributable to the underlying properties and the net
profits interests for the years ended December 31, 2000 and 1999 were as
follows:

<TABLE>
<CAPTION>
                                                           2000        1999
                                                        ----------- -----------
     <S>                                                <C>         <C>
     Production
     Underlying Properties
      Gas--Sales (Mcf).................................  36,842,156  34,188,398
       Average per day (Mcf)...........................     100,662     102,055
      Oil--Sales (Bbls)................................     399,929     388,038
       Average per day (Bbls)..........................       1,093       1,158
     Net Profits Interests
      Gas--Sales (Mcf).................................  18,199,754  15,583,364
       Average per day (Mcf)...........................      49,726      46,518
      Oil--Sales (Bbls)................................     198,677     190,668
       Average per day (Bbls)..........................         543         569
     Average Sales Price
      Gas (per Mcf).................................... $      3.14 $      2.12
      Oil (per Bbl).................................... $     28.67 $     16.53
</TABLE>

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 natural 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
  tight sands tax credit, since the trust is not a taxable entity and the
  credit inures directly to the benefit of the unitholder (see "Regulation--
  Tight Sands Tax Credit").

    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.

                                       6
<PAGE>

  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 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 Cross Timbers 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 80% net profits interest in the
properties have effectively been reduced to reflect recovery of the trust's
80% portion of applicable production and development costs, excluding
overhead. 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. These 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 $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
$9.44 per Mcf in 2000, $2.23 per Mcf in 1999 and $2.01 per Mcf in 1998.

  Proved Reserves

  The following table reconciles the change in proved reserves attributable to
the underlying properties and net profits interests from December 31, 1998
through December 31, 2000:

<TABLE>
<CAPTION>
                                                Underlying      Net Profits
                                                Properties       Interests
  (in thousands)                              ---------------  ---------------
                                                Gas     Oil      Gas     Oil
                                               (Mcf)   (Bbls)   (Mcf)   (Bbls)
                                              -------  ------  -------  ------
  <S>                                         <C>      <C>     <C>      <C>
  Balance, December 31, 1998................. 515,073  4,030   282,297  2,193
    Extensions, discoveries and other
     additions...............................  28,262     89    16,173     51
    Revisions of prior estimates.............  (3,778)   540     5,034    358
    Production--sales volumes................ (34,188)  (388)  (15,583)  (191)
                                              -------  -----   -------  -----
  Balance, December 31, 1999................. 505,369  4,271   287,921  2,411
    Extensions, discoveries and other
     additions...............................  29,076    132    20,605     94
    Revisions of prior estimates.............  17,640    544    81,922    957
    Property sales...........................    (225)   (10)      (98)    (4)
    Production--sales volumes................ (36,842)  (400)  (18,200)  (199)
                                              -------  -----   -------  -----
  Balance, December 31, 2000................. 515,018  4,537   372,150  3,259
                                              =======  =====   =======  =====
</TABLE>

  Extensions, discoveries and additions in 1999 and 2000 are primarily related
to delineation of additional proved undeveloped reserves in the Anadarko
Basin. Upward revisions of prior estimates of the proved reserves for the
underlying properties during 2000 are because of lower than estimated
production decline. Upward

                                       7
<PAGE>

revisions of prior estimates of proved gas reserves of the net profits
interests as compared with downward revisions of the underlying properties in
1999, and higher upward revisions for the net profits interests as compared
with the underlying properties in 2000, were caused by higher year-end gas
prices which resulted in increased gas reserves allocated to the trust.

  Proved Developed Reserves

  The following are estimated quantities of proved developed reserves
attributable to the underlying properties and net profits interests as of
December 31, 1998, 1999 and 2000:

<TABLE>
<CAPTION>
                                                     Underlying    Net Profits
                                                     Properties     Interests
  (in thousands)                                   -------------- --------------
                                                     Gas    Oil     Gas    Oil
                                                    (Mcf)  (Bbls)  (Mcf)  (Bbls)
                                                   ------- ------ ------- ------
  <S>                                              <C>     <C>    <C>     <C>
  December 31, 1998............................... 435,328 3,368  249,215 1,934
                                                   ======= =====  ======= =====
  December 31, 1999............................... 431,399 3,595  253,567 2,105
                                                   ======= =====  ======= =====
  December 31, 2000............................... 434,904 3,935  316,278 2,843
                                                   ======= =====  ======= =====
</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 attributable to the underlying properties and
net profits interests as of December 31, 2000, 1999 and 1998:

<TABLE>
<CAPTION>
                                                          December 31
     (in thousands)                             --------------------------------
                                                   2000       1999       1998
                                                ---------- ---------- ----------
     <S>                                        <C>        <C>        <C>
     Underlying Properties
     Future cash inflows....................... $4,972,727 $1,240,476 $1,087,660
     Future costs:
       Production..............................    831,037    388,923    364,930
       Development.............................     60,211     48,861     48,212
                                                ---------- ---------- ----------
     Future net cash flows.....................  4,081,479    802,692    674,518
     10% discount factor.......................  2,141,117    393,924    327,341
                                                ---------- ---------- ----------
     Standardized measure...................... $1,940,362 $  408,768 $  347,177
                                                ========== ========== ==========
     Net Profits Interests
     Future cash inflows....................... $3,593,473 $  707,067 $  595,301
     Future production taxes...................    328,290     64,913     55,686
                                                ---------- ---------- ----------
     Future net cash flows.....................  3,265,183    642,154    539,615
     10% discount factor.......................  1,712,894    315,140    261,873
                                                ---------- ---------- ----------
     Standardized measure...................... $1,552,289 $  327,014 $  277,742
                                                ========== ========== ==========
</TABLE>

                                       8
<PAGE>

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

  The following summarizes the changes in the standardized measure during 2000
and 1999 for the net profits interests. Significant upward revisions in 2000
were caused by the increase in year-end gas prices:

<TABLE>
<CAPTION>
                                                             2000       1999
     (in thousands)                                       ----------  --------
     <S>                                                  <C>         <C>
     Standardized measure, January 1....................  $  327,014  $277,742
      Extensions, discoveries and other additions.......      84,743    13,333
      Accretion of discount.............................      28,597    25,459
      Revisions of prior estimates, changes in price and
       other............................................   1,168,847    43,620
      Property sales....................................        (100)      -0-
      Royalty income....................................     (56,812)  (33,140)
                                                          ----------  --------
     Standardized measure, December 31..................  $1,552,289  $327,014
                                                          ==========  ========
</TABLE>

Regulation

   Natural Gas Regulation

  The interstate transportation and sale for resale of natural gas is subject
to federal regulation, including transportation rates charged, storage tariffs
and various other matters, by the Federal Energy Regulatory Commission.
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, and what effect,
if any, such proposals might have on the operations of the underlying
properties.

   Environmental Regulation

  Companies that are engaged in the oil and gas industry are affected by
federal, state and local laws regulating the discharge of materials into the
environment. Those laws may impact operations of the underlying properties. No
material expenses have been incurred on the underlying properties in complying
with environmental laws and regulations. Cross Timbers does not expect that
future compliance will have a material adverse effect on the trust.

   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.

   Other Regulation

  The Minerals Management Service of the United States Department of the
Interior is evaluating existing methods of settling royalties on federal and
Native American oil and gas leases. Seven percent of the net acres of the
underlying properties, primarily located in Wyoming, involve federal leases.
Although the final rules could cause an increase in the federal royalties to
be paid on these properties, and, correspondingly, decrease the revenue to
Cross Timbers and the trust, Cross Timbers' management does not believe that
the proposed rule changes will have a significant detrimental effect on trust
distributions.

  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

                                       9
<PAGE>

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.

   Tight Sands Tax Credit

  The trust receives royalty income from tight sands wells, certain production
from which qualifies for the federal income tax credit for producing
nonconventional fuels under Section 29 of the Internal Revenue Code. The
Section 29 tax credit is available for tight sands gas produced and sold
through 2002 from wells drilled prior to January 1, 1993 and after November 5,
1990, or after December 31, 1979 if the related formation was dedicated to
interstate commerce as of April 20, 1977. This tax credit is approximately
$0.52 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.

Pricing and Sales Information

  A subsidiary of Cross Timbers purchases Cross Timbers' natural gas
production at the monthly published price, then sells the gas to third parties
for the best available price. Any marketing gains or losses are not included
in trust net proceeds. Oil production is generally marketed at the wellhead to
third parties at the best available price. Cross Timbers arranges for some of
its natural gas to be processed by unaffiliated third parties and markets the
natural gas liquids. The natural gas attributable to the underlying properties
is marketed under contracts existing at trust inception. Contracts covering
production from the Major County area are generally for the life of the lease,
and the contract for the majority of production from the Hugoton area expires
in 2004. If new contracts are entered with unaffiliated third parties, the
proceeds from sales under those new contracts will be included in gross
proceeds from the underlying properties. If new contracts are entered with
Cross Timbers' marketing subsidiary, it may charge Cross Timbers a fee that
may not exceed 2% of the sales price of the oil and natural gas received from
unaffiliated parties. The sales price is net of any deductions for
transportation from the wellhead to the unaffiliated parties and any gravity
or quality adjustments.

Item 3. Legal Proceedings

  Cross Timbers is a defendant in three separate lawsuits that could, if
adversely determined, decrease future trust distributable income. Damages
relating to production prior to the formation of the trust will be borne by
Cross Timbers.

  On April 3, 1998, a class action lawsuit, Booth, et al. v. Cross Timbers Oil
Company, was filed in the District Court of Dewey County, Oklahoma by royalty
owners of natural gas wells in Oklahoma. The plaintiffs allege that since 1991
Cross Timbers has underpaid royalty owners as a result of reducing royalties
for improper charges for production, marketing, gathering, processing and
transportation costs and selling natural gas through affiliated companies at
prices less favorable than those paid by third parties. Cross Timbers believes
that it has strong defenses to this lawsuit and intends to vigorously defend
its position. However, if Cross Timbers ultimately makes any settlement
payments, the trust will bear its 80% share of such settlement related to
production from the underlying properties for periods since December 1, 1998.
Additionally, if a judgment or settlement increases the amount of future
payments to royalty owners, the trust would bear its proportionate share of
the increased payments through reduced net proceeds. The amount of any
potential settlement related to the trust and reduction in net proceeds is not
presently determinable, but, in Cross Timbers management's opinion, is not
currently expected to be material to the trust's annual distributable income,
financial position or liquidity.

  A second lawsuit, United States of America ex rel. Grynberg v. Cross Timbers
Oil Company, et al., was filed in the United States District Court for the
Western District of Oklahoma. This action alleges that Cross Timbers underpaid
royalties on natural gas produced from federal leases and lands owned by
Native Americans by at least 20% during the past 10 years as a result of
mismeasuring the volume of natural gas and wrongfully

                                      10
<PAGE>

analyzing its heating content. The suit, which was brought under the qui tam
provisions of the U.S. False Claims Act, seeks treble damages for the unpaid
royalties (with interest), civil penalties between $5,000 and $10,000 for each
violation of the U.S. False Claims Act, and an order for Cross Timbers to
cease the allegedly improper measuring practices. The cases against Cross
Timbers and other defendants have been consolidated in the United States
District Court for Wyoming. Cross Timbers and other defendants have filed a
motion to dismiss the lawsuit. The motion to dismiss has been heard by the
Court and a decision is pending. Cross Timbers believes that the allegations
of this lawsuit are without merit and intends to vigorously defend the action.
However, an order to change measuring practices or a related settlement could
adversely affect the trust by reducing net proceeds in the future by an amount
that is presently not determinable, but, in Cross Timbers management's
opinion, is not expected to be material to the trust's annual distributable
income, financial position or liquidity.

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

  Certain of the trust properties are involved in various other lawsuits and
certain governmental proceedings arising in the ordinary course of business.
Cross Timbers 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 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 2000.

                                      11
<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
                                                      ------------ ------------
  <S>                                                 <C>          <C>
  Royalty Income..................................... $ 56,812,141 $ 33,139,662
  Distributable Income...............................   56,712,080   33,090,049
  Distributable Income per Unit......................     1.417802     0.827253
  Distributions per Unit.............................     1.417802     0.827253
  Total Assets at Year-End...........................  232,057,603  237,980,449
</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 year ended December 31, 2000 on pages 5 through 7 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 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' 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

                                      12
<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 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 8 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.

                                   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 in 2000 as specified
in the trust indenture:

<TABLE>
<CAPTION>
                                          Other Annual
        Name and Principal Position     Compensation (1)
        ---------------------------     ----------------
        <S>                             <C>
        Bank of America, N.A., Trustee      $35,000
</TABLE>
--------
(1) Under the trust indenture, the trustee is entitled to an annual
    administrative fee, paid in equal monthly installments. Such fee is
    adjusted annually based on an oil and gas industry index. Upon termination
    of the trust, the trustee is entitled to a termination fee of $15,000.

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    21,705,893 units (1)  54.3%
        810 Houston Street, Suite
        2000
        Fort Worth, TX 76102
</TABLE>
--------
(1) Cross Timbers has the sole power to vote and dispose of 21,705,893 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, an aggregate of 21,000 units without the right
to vote any 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.


                                      13
<PAGE>

Item 13. Certain Relationships and Related Transactions

  In computing royalty income paid to the trust for the net profits interests,
Cross Timbers deducts an overhead charge for reimbursement of administrative
expenses on the underlying properties it operates. This charge at December 31,
2000 was approximately $615,000 per month, or $7,380,000 annually (net to the
trust of $492,000 per month or $5,904,000 annually), and is subject to annual
adjustment based on an oil and gas industry index.

  Cross Timbers sells a significant portion of natural gas production from the
underlying properties to certain of its wholly owned subsidiaries under
contracts in existence when the trust was created, generally at amounts
approximating monthly published prices. For further information, see Item 2.
"Hugoton Area," "Anadarko Basin," "Green River Basin" and "Pricing and Sales
Information."

                                    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 year ended December 31, 2000
    and 1999
    Statements of Changes in Trust Corpus for the year ended December 31,
    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

<TABLE>
     <C>    <S>
     (4)(a) Hugoton Royalty Trust Indenture by and between NationsBank, N.A.
            (now Bank of America, N.A.), as trustee, and Cross Timbers Oil
            Company heretofore filed as Exhibit 4.1 to the trust's Registration
            Statement No. 333-68441 on Form S-1 filed with the Securities and
            Exchange Commission on December 4, 1998, is incorporated herein by
            reference.
        (b) Net Overriding Royalty Conveyance (Hugoton Royalty Trust, 80%--
            Kansas) as amended and restated from Cross Timbers Oil Company to
            NationsBank, N.A. (now Bank of America, N.A.), as trustee, and
            Cross Timbers Oil Company dated December 1, 1998, heretofore filed
            as Exhibit 10.1.1 to the trust's Registration Statement No. 333-
            68441 on Form S-1 filed with the Securities and Exchange Commission
            on March 16, 1999, is incorporated herein by reference.
        (c) Net Overriding Royalty Conveyance (Hugoton Royalty Trust, 80%--
            Oklahoma) as amended and restated from Cross Timbers Oil Company to
            NationsBank, N.A. (now Bank of America, N.A.), as trustee, and
            Cross Timbers Oil Company dated December 1, 1998, heretofore filed
            as Exhibit 10.1.1 to the trust's Registration Statement No. 333-
            68441 on Form S-1 filed with the Securities and Exchange Commission
            on March 16, 1999, is incorporated herein by reference.
        (d) Net Overriding Royalty Conveyance (Hugoton Royalty Trust, 80%--
            Wyoming) as amended and restated from Cross Timbers Oil Company to
            NationsBank, N.A. (now Bank of America, N.A.), as trustee, and
            Cross Timbers Oil Company dated December 1, 1998, heretofore filed
            as Exhibit 10.1.1 to the trust's Registration Statement No. 333-
            68441 on Form S-1 filed with the Securities and Exchange Commission
            on March 16, 1999, is incorporated herein by reference.
     (13)   Hugoton 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.
</TABLE>

                                      14
<PAGE>

    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

  The trust filed the following report on Form 8-K during the last quarter of
the trust's fiscal year ended December 31, 2000:

    On December 20, 2000, the trust filed a report on Form 8-K to announce
  development plans and operational outlook for properties underlying the
  trust, as provided to the trustee by Cross Timbers Oil Company.

                                      15
<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.

                                          HUGOTON ROYALTY TRUST
                                          By BANK OF AMERICA, N.A., TRUSTEE

                                                       RON E. HOOPER
                                          By: _________________________________
                                                       Ron E. Hooper
                                                   Senior Vice President

                                          CROSS TIMBERS OIL COMPANY


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

              (The trust has no directors or executive officers.)

                                      16