<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
1999

                             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
                                                         (Zip Code)
               Trustee
           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, 2000, 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, 2000) held by non-
affiliates of the registrant on that date was approximately $142.7 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:

                  1999 Annual Report to Unit Holders--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, 40,000,000 units of beneficial interest were issued to Cross Timbers.
On April 8, 1999, Cross Timbers sold 15,000,000 units in the trust's initial
public offering. An additional 2,004,000 units were sold on May 7, 1999 by
Cross Timbers pursuant to the underwriters' overallotment option. The trust
did not receive any proceeds from the sale of trust units. As of March 1,
2000, Cross Timbers owned 22,922,316 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 are computed differently.
Net proceeds for this period are 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.

  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

                                       1
<PAGE>

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 1999,
as well as 91% of the estimated proved reserves of the net profits interests
at December 31, 1999 (based on the discounted present value 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. Cross Timbers
is actively exploring and developing these formations on the underlying
properties.

  Sales volumes from the underlying properties in the Hugoton area averaged
approximately 34,300 Mcf of natural gas per day and 55 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 74% of its throughput from underlying properties, which, in
recent months, has been approximately 26,000 Mcf per day from 243 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. Cross Timbers does not pay the gathering
subsidiary for fuel, gathering or compression. Under long-term contracts, the
gathering subsidiary sells residue volumes to Cross Timbers' marketing
affiliate at a price equal to 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.


                                       2
<PAGE>

  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.

  Cross Timbers plans to develop the Chase formation primarily through infill
drilling of up to 35 wells in Kansas. In June 1999, Oklahoma regulations were
amended to allow increased drilling density in the Oklahoma panhandle where
Cross Timbers has approximately 200 infill well locations on the underlying
properties. Cross Timbers also plans to develop the 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 further test
wells are planned for 2000.

  Cross Timbers drilled 5 gross (4 net) wells in 1999 to the Chester, Council
Grove and Chase formations, all of which were successfully completed. Cross
Timbers plans to drill up to three wells and perform up to 24 workovers in the
Hugoton area during 2000.

  Anadarko Basin

  Major County Area. Cross Timbers is one of the largest producers in the
Ringwood, Northwest Okeene and Cheyenne Valley fields in Major County,
Oklahoma. Average 1999 net daily sales volumes from the underlying properties
were 30,800 Mcf of gas and 865 Bbls of oil.

  Oil and natural gas were discovered in the Major County area in 1945. 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 gathering fee of $0.313 per Mcf of residue gas. This gathering fee was
previously approved by the Federal Energy Regulatory Commission when the
gathering subsidiary was regulated. During 1999, the gathering system
collected approximately 21,000 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 80,000 Mcf
per month from 25 wells, for a historical average fee of approximately $0.125
per Mcf.

  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.

                                       3
<PAGE>

  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 8 gross (5.5 net) wells in 1999 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 13 wells and perform up to 42 workovers in the Major
County area during 2000.

  Elk City Field. The Elk City Field is located in Beckham and Washita
counties of Western Oklahoma. Average 1999 sales volumes from the underlying
properties in the Elk City Field were approximately 3,900 Mcf of gas and 138
Bbls of oil per day.

  The Elk City Field was discovered in 1947 and has been extensively
developed. Production is from the Hoxbar (9,500 feet), Atoka (13,100 feet) and
Morrow (15,500 feet) zones. Cross Timbers has increased production primarily
by adding mechanical treatments to stimulate production rates and opening new
producing zones in existing wells. Opportunities remain for additional
development in the field. Cross Timbers added significant additional reserves
through recent recompletions to the Atoka formation and plans to drill one
well to the Hoxbar formation in 2000.

  A third party processes natural gas from the Elk City Field and pays Cross
Timbers 80% of the proceeds received from the sale of the liquids. Cross
Timbers sells the residue natural gas to its marketing subsidiary, which pays
Cross Timbers the average price of several published indices less pipeline
access fees.

  Green River Basin

  The Green River Basin is located in southwestern Wyoming. Cross Timbers'
1999 average daily sales volumes from the underlying properties in the
Fontenelle field were approximately 27,600 Mcf of natural gas and 59 Bbls of
oil. Natural gas was discovered in the Fontenelle area 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.

  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 1999, the fuel charge was 0.5% 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. Condensate is sold at the lease to an independent third party
at market rates. 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.

  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,


                                       4
<PAGE>

  .  deepening existing wells to new producing zones, and

  .  drilling additional wells.

  Cross Timbers drilled 7 gross (6.9 net) wells in the Fontenelle Unit in
1999, all of which were successfully completed. Cross Timbers plans to drill
up to five wells and perform up to five workovers in the Green River Basin
during 2000.

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, 1999. 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, 1999:

<TABLE>
<CAPTION>
                                       Operated    Non-Operated
                                        Wells          Wells          Total
                                    -------------- ------------- ---------------
                                    Gross    Net   Gross   Net   Gross    Net
                                    ------ ------- ------------- ------ --------
     <S>                            <C>    <C>     <C>    <C>    <C>    <C>
     Gas...........................  1,025   933.8   257    59.8  1,282    993.6
     Oil...........................    133   119.7     6     1.1    139    120.8
                                    ------ ------- -----  ------ ------ --------
     Total.........................  1,158 1,053.5   263    60.9  1,421  1,114.4
                                    ====== ======= =====  ====== ====== ========
</TABLE>

  There were five (2.1 net) wells in process of drilling at December 31, 1999.

  The following is a summary of the number of wells drilled on the underlying
properties during the year ended December 31, 1999. Unless otherwise
indicated, all wells drilled are developmental.

<TABLE>
<CAPTION>
                                                                      Gross Net
                                                                      ----- ----
     <S>                                                              <C>   <C>
     Completed gas wells (a).........................................   40  32.5
     Non-productive--exploratory.....................................    1   1.0
                                                                       ---  ----
     Total...........................................................   41  33.5
                                                                       ===  ====
</TABLE>
--------
(a) Included in completed gas wells are 7 gross (1.1 net) wells drilled on
    nonoperated interests.

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

                                       5
<PAGE>

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 year ended December 31, 1999 were as follows:

<TABLE>
<CAPTION>
     Production
     <S>                                                            <C>
     Underlying Properties
      Gas--Sales (Mcf).............................................  34,188,398
       Average per day (Mcf).......................................     102,055
      Oil--Sales (Bbls)............................................     388,038
       Average per day (Bbls)......................................       1,158


     Net Profits Interests
      Gas--Sales (Mcf).............................................  15,583,364
       Average per day (Mcf).......................................      46,518
      Oil--Sales (Bbls)............................................     190,668
       Average per day (Bbls)......................................         569


     Average Sales Price
      Gas (per Mcf)................................................ $      2.12
      Oil (per Bbl)................................................ $     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.

    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, 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.

                                       6
<PAGE>

  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
ownership 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 $22.75 per Bbl in 1999 and
$9.50 per Bbl in 1998. The year-end weighted average realized gas prices used
to determine the standardized measure were $2.23 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 for the year ended
December 31, 1999 (in thousands):

<TABLE>
<CAPTION>
                                             Underlying        Net Profits
                                             Properties         Interests
                                           ----------------  ----------------
                                             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
                                           ========  ======  ========  ======
</TABLE>

  Extensions, discoveries and additions are primarily related to delineation
of additional proved undeveloped reserves in the Anadarko Basin during 1999.
Upward revisions of prior estimates of proved gas reserves of the net profits
interests as compared with downward revisions of the underlying properties
were caused by higher year-end 1999 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 and 1999 (in thousands):

<TABLE>
<CAPTION>
                                                   Underlying      Net Profits
                                                   Properties       Interests
                                                 --------------- ---------------
                                                   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
                                                 ======== ====== ======== ======
</TABLE>


                                       7
<PAGE>

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, 1999 and 1998 (in thousands):

<TABLE>
<CAPTION>
                                                                December 31
     Underlying Properties                                 ---------------------
                                                              1999       1998
                                                           ---------- ----------
     <S>                                                   <C>        <C>
     Future cash inflows.................................  $1,240,476 $1,087,660
     Future costs:
       Production........................................     388,923    364,930
       Development.......................................      48,861     48,212
                                                           ---------- ----------
     Future net cash flows...............................     802,692    674,518
     10% discount factor.................................     393,924    327,341
                                                           ---------- ----------
     Standardized measure................................  $  408,768 $  347,177
                                                           ========== ==========

<CAPTION>
                                                                December 31
     Net Profits Interests                                 ---------------------
                                                              1999       1998
                                                           ---------- ----------
     <S>                                                   <C>        <C>
     Future cash inflows.................................  $  707,067 $  595,301
     Future production taxes.............................      64,913     55,686
                                                           ---------- ----------
     Future net cash flows...............................     642,154    539,615
     10% discount factor.................................     315,140    261,873
                                                           ---------- ----------
     Standardized measure................................  $  327,014 $  277,742
                                                           ========== ==========
</TABLE>

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

  The following summarizes the changes in the standardized measure during 1999
for the net profits interests (in thousands):

<TABLE>
     <S>                                                               <C>
     Standardized measure, January 1.................................. $277,742
      Extensions, discoveries and other additions.....................   13,333
      Accretion of discount...........................................   25,459
      Revisions of prior estimates, changes in price and other........   43,620
      Royalty income..................................................  (33,140)
                                                                       --------
     Standardized measure, December 31................................ $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

                                       8
<PAGE>

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.

  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 markets Cross Timbers' natural gas production,
and the natural gas is sold on a monthly basis to third parties for the best
available price. 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 two separate lawsuits that could, if
adversely determined, decrease future trust distributable income. Damages
relating to production prior to the formation of the trust will be borne by
Cross Timbers.


                                       9
<PAGE>

  A class action lawsuit, Booth, et al. v. Cross Timbers Oil Company, was
filed on April 3, 1998 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. The
plaintiffs are seeking an accounting and payment of the monies allegedly owed
to them. A hearing on the class certification has not been scheduled. Cross
Timbers believes that it has strong defenses to this lawsuit and intends to
vigorously defend its position. However, if Cross Timbers ultimately makes any
settlement payments, the trust will bear its 80% share of such settlement
related to production from the underlying properties for periods since
December 1, 1998. Additionally, if a judgment or settlement increases the
amount of future payments to royalty owners, the trust would bear its
proportionate share of the increased payments through reduced net proceeds.
The amount of any reduction in net proceeds is not presently determinable,
but, in Cross Timbers management's opinion, is not currently expected to be
material to the trust's annual distributable income, financial position or
liquidity.

  A second lawsuit, United States of America ex rel. Grynberg v. Cross Timbers
Oil Company, et al., was filed in the United States District Court for the
Western District of Oklahoma. This action alleges that Cross Timbers underpaid
royalties on natural gas produced from federal leases and lands owned by
Native Americans by at least 20% during the past 10 years as a result of
mismeasuring the volume of natural gas and wrongfully analyzing its heating
content. The suit, which was brought under the qui tam provisions of the U.S.
False Claims Act, seeks treble damages for the unpaid royalties (with
interest), civil penalties between $5,000 and $10,000 for each violation of
the U.S. False Claims Act, and an order for Cross Timbers to cease the
allegedly improper measuring practices. The plaintiff has made similar
allegations in over 70 actions filed against over 300 other companies. After
its review, the U. S. Department of Justice decided in April 1999 not to
intervene, and the court unsealed the case in May 1999. A federal multi-
district litigation panel has ordered that most of the suits filed by
Grynberg, including the case against Cross Timbers, be transferred and
consolidated to the federal district court in Wyoming. Cross Timbers and other
defendants have filed a motion to dismiss the lawsuit. Cross Timbers believes
that the allegations of this lawsuit are without merit and intends to
vigorously defend the action. However, an order to change measuring practices
or a related settlement could adversely affect the trust by reducing net
proceeds in the future by an amount that is presently not determinable, but,
in Cross Timbers management's opinion, is not expected to be material to the
trust's annual distributable income, financial position or liquidity.

  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 1999.

                                      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, 1999 is
incorporated herein by reference.

Item 6. Selected Financial Data

<TABLE>
<CAPTION>
                                                                  Year Ended
                                                               December 31, 1999
                                                               -----------------
  <S>                                                          <C>
  Royalty Income..............................................   $ 33,139,662
  Distributable Income........................................     33,090,049
  Distributable Income per Unit...............................       0.827253
  Distributions per Unit......................................       0.827253
  Total Assets at Year-End....................................    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, 1999 on pages 5, 6 and 7 of the
trust's Annual Report to unitholders for the year ended December 31, 1999 is
incorporated herein by reference.

  Year 2000

  "Year 2000," or the ability of computer systems to process dates with years
beyond 1999, affects almost all companies and organizations. Computer systems
that are not Year 2000 compliant could have material adverse effects on
companies and organizations that rely upon those systems.

  The trust's timely receipt of royalty income and disbursement of
distributable income to unitholders is largely dependent upon performance of
computer systems and computer-controlled equipment of Cross Timbers,
ChaseMellon Shareholder Services, L.L.C. and other third parties, including
oil and natural gas purchasers and significant service providers such as
electric utility companies and natural gas plant, pipeline and gathering
system operators. Since the trust does not use the trustee's computer systems
in any significant capacity, the trustee's Year 2000 compliance does not
materially affect the trust.

  Cross Timbers completed remediation and testing of its significant computer
systems and computer-controlled field equipment in December 1999. No costs of
such modifications were incurred by the trust. Cross Timbers has not
experienced any material Year 2000 system failures, and does not foresee any
material system failures in the coming months. Cross Timbers also identified
significant third parties whose Year 2000 compliance could affect Cross
Timbers and formally inquired about their Year 2000 status. The trustee and
Cross Timbers are not aware of any significant third parties who experienced
material Year 2000 system failures. Despite their efforts to assure that such
third parties are Year 2000 compliant, neither the trustee nor Cross Timbers
can provide assurance that significant third parties will not experience
material Year 2000 system failures in the coming months. Such failures could
have a material adverse impact on timely trust distributions to unitholders.
Although the potential effect of Year 2000 noncompliance by third parties is
unknown, Cross Timbers has developed contingency plans in the event of
potential problems resulting from related system failures.

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.

                                      11
<PAGE>

Consequently, the trust is exposed to market risk from fluctuations in oil and
gas prices. The trust is a passive entity and, other than the trust's ability
to periodically borrow money as necessary to pay expenses, liabilities and
obligations of the trust that cannot be paid out of cash held by the trust,
the trust is prohibited from engaging in borrowing transactions. The amount of
any such borrowings is unlikely to be material to the trust. In addition, the
trustee is prohibited by the trust indenture from engaging in any business
activity or causing the trust to enter into any investments other than
investing cash on hand in specific short-term cash investments. Therefore, the
trust cannot hold any derivative financial instruments. As a result of the
limited nature of 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 report thereon of Arthur Andersen LLP dated March 1, 2000, appearing on
pages 8 through 12 of the trust's Annual Report to unitholders for the year
ended December 31, 1999 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 year ended December 31, 1999.

                                   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 1999 as specified
in the trust indenture:

<TABLE>
<CAPTION>
                                          Other Annual
        Name and Principal Position     Compensation (1)
        ---------------------------     ----------------
        <S>                             <C>
        Bank of America, N.A., Trustee      $29,333
</TABLE>
--------
(1) Under the trust indenture, the trustee is entitled to an administrative
    fee of $35,000 per year, 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, 2000 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       22,922,316 Units (1)    57.3%
        810 Houston Street, Suite 2000
        Fort Worth, TX 76102
</TABLE>
--------
(1) Cross Timbers has the sole power to vote and dispose of all 22,922,316
    units.

                                      12
<PAGE>

  (b) Security Ownership of Management. The trust has no directors or
executive officers. As of March 1, 2000, 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.

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,
1999 was approximately $580,000 per month, or $6,960,000 annually (net to the
trust of $464,000 per month or $5,568,000 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 spot market 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, 1999
    and 1998
    Statement of Distributable Income for the year ended December 31, 1999
    Statement of Changes in Trust Corpus for the year ended December 31,
    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.
</TABLE>

                                      13
<PAGE>



<TABLE>
 <C>           <S>
           (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, 1999.

        (23.1) Consent of Arthur Andersen LLP

        (23.2) Consent of Miller and Lents, Ltd.
</TABLE>

    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, 1999,
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.

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

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

                                          CROSS TIMBERS OIL COMPANY


                                                     LOUIS G. BALDWIN
Date: March 30, 2000                      By: _________________________________
                                                     Louis G. Baldwin
                                               Executive Vice President and
                                                  Chief Financial Officer

              (The Trust has no directors or executive officers.)

                                      15