<Page>

                                                                      EXHIBIT 13


HUGOTON ROYALTY TRUST

GLOSSARY OF TERMS

The following are definitions of significant terms used in this Annual Report:


Bbl                            Barrel (of oil)

Bcf                            Billion cubic feet (of natural gas)

Mcf                            Thousand cubic feet (of natural gas)

MMBtu                          One million British Thermal Units, a common
                               energy measurement

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

net profits income             Net proceeds multiplied by the net profits
                               percentage

                               of 80%, which is paid to the trust by XTO Energy.
                               "Net profits income" is referred to as "royalty
                               income" for tax reporting purposes.

net profits interest           An interest in an oil and gas property measured
                               by net profits from the sale of production,
                               rather than a specific portion of production.
                               The following defined net profits interests were
                               conveyed to the trust from the underlying
                               properties:

                               80% net profits interests - interests that
                               entitle the trust to receive 80% of the net
                               proceeds from the underlying properties that are
                               working interests in Kansas, Oklahoma and
                               Wyoming.

underlying properties          XTO Energy's interest in certain oil
                               and gas properties from which the net profits
                               interests were conveyed. The underlying
                               properties include working interests in
                               predominantly gas-producing properties located in
                               Kansas, Oklahoma and Wyoming.

working interest               An operating interest in an oil and gas
                               property that provides the owner a specified
                               share of production that is subject to all
                               production and development costs
<Page>

THE TRUST

Hugoton Royalty Trust was created on December 1, 1998 when XTO Energy Inc.
(formerly known as Cross Timbers Oil Company) conveyed 80% net profits interests
in certain predominantly gas-producing properties located in Kansas, Oklahoma
and Wyoming to the trust. The net profits interests are the only assets of the
trust, other than cash held for trust expenses and for distribution to
unitholders.

Net profits income received by the trust on the last business day of each month
is calculated and paid by XTO Energy based on net proceeds received from the
underlying properties in the prior month. Distributions, as calculated by the
trustee, are paid to month-end unitholders of record within ten business days.


UNITS OF BENEFICIAL INTEREST

The units of beneficial interest in the trust began trading on the New York
Stock Exchange on April 9, 1999 under the symbol "HGT." The following are the
high and low unit sales prices and total cash distributions per unit paid by the
trust during each quarter of 2001 and 2000:

<Table>
<Caption>
                                                                     Sales Price
                                                           ----------------------------------    Distributions
     Quarter                                                    High                Low             per Unit
-----------------------------------------------------      --------------    ----------------   --------------

<S>                                                       <C>                <C>              <C>
     2001
First................................................        $      16.000      $      13.500    $  0.841362
Second...............................................               17.010             12.000       0.543291
Third................................................               13.700              9.700       0.381796
Fourth...............................................               11.670              9.910       0.211827
                                                                                                 ------------
                                                                                                 $  1.978276
                                                                                                 ============

     2000
First................................................        $       9.000      $       7.625    $  0.273482
Second...............................................               13.000              8.188       0.281612
Third................................................               15.688             11.188       0.404911
Fourth...............................................               15.500             12.375       0.457797
                                                                                                 ------------
                                                                                                 $  1.417802
                                                                                                 ============
</Table>

At December 31, 2001, there were 40,000,000 units outstanding and approximately
156 unitholders of record; 17,757,839 of these units were held by depository
institutions. As of March 1, 2002, XTO Energy owned 21,705,893 units.

FORWARD-LOOKING STATEMENTS

This Annual Report, including the accompanying Form 10-K, includes
"forward-looking statements" within the meaning of Section 27A of the Securities
Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934,
as amended. All statements other than statements of historical fact included in
this Annual Report and Form 10-K, including, without limitation, statements
regarding estimates of proved reserves, future development plans and costs, and
industry and market conditions, are forward-looking statements that are subject
to a number of risks and uncertainties which are detailed in Part II, Item 7 of
the accompanying Form 10-K. Although XTO Energy believes that the expectations
reflected in such forward-looking statements are reasonable, neither XTO Energy
nor the trustee can give any assurance that such expectations will prove to be
correct.


                                                                               1
<Page>

SUMMARY

The trust was created to collect and distribute to unitholders monthly net
profits income related to the 80% net profits interests. Such net profits income
is calculated as 80% of the net proceeds received from certain working interests
in predominantly gas-producing properties in Kansas, Oklahoma and Wyoming. Net
proceeds from properties in each state are calculated by deducting production
costs, development costs and overhead from revenues. If monthly costs exceed
revenues from the underlying properties in any state, such excess costs must be
recovered, with accrued interest, from future net proceeds of that state and
cannot reduce net profits income from another state. Excess costs generally can
occur during periods of higher development activity and lower gas prices.

Unitholders may be eligible to receive the following tax benefits, but should
consult their tax advisors:

     -  THE NONCONVENTIONAL FUEL SOURCE TAX CREDIT is related to tight sands gas
        production sold through 2002 from wells drilled on the underlying
        properties 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 may be used to
        reduce the unitholder's regular income tax liability, but not below his
        tentative minimum tax. Congress is considering an extension of existing
        energy tax credits beyond the scheduled December 31, 2002 expiration
        date, as well as the creation of similar new tax credits. During 2001,
        the U.S. House passed a bill that would extend existing tax credits on
        certain production, while the U.S. Senate is considering a separate bill
        to address energy tax credits. The potential effect of any final
        legislation on unitholders is unknown.

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

            As an example, a unitholder that acquired units in January 2001 and
            held them throughout 2001 would be entitled to a cost depletion
            deduction of approximately 5% of his cost. Assuming a cost of $13.50
            per unit, cost depletion would offset 33% of 2001 taxable trust
            income. After considering the tight sands tax credit and assuming a
            30% tax rate, the 2001 taxable equivalent return as a percentage of
            unit cost would be 17%. (NOTE- because the units are a depleting
            asset, a portion of this return is effectively a return of capital.)


                                                                               2
<Page>

TO UNITHOLDERS

We are pleased to present the 2001 Annual Report of the Hugoton Royalty Trust.
This report includes a copy of the trust's 2001 Form 10-K as filed with the
Securities and Exchange Commission. Both reports contain important information
about the trust's net profits interests, including information provided to the
trustee by XTO Energy, and should be read in conjunction with each other.

For the year ended December 31, 2001, net profits income totaled $79,272,395.
After adding interest income of $136,177 and deducting trust administration
expense of $277,532, distributable income was $79,131,040 or $1.978276 per unit.
Net profits income and distributions were 40% higher than 2000 amounts primarily
because of higher average gas prices.

Natural gas prices averaged $4.30 per Mcf for 2001, 37% higher than the 2000
average price of $3.14 per Mcf. The average 2001 oil price was $27.60 per Bbl,
4% lower than the 2000 average price of $28.67 per Bbl.

Gas sales volumes from the underlying properties for 2001 were 36,597,937 Mcf,
or 100,268 Mcf per day, versus 100,662 Mcf per day in 2000. Oil sales volumes
from the underlying properties were 393,731 Bbls, or 1,079 Bbls per day in 2001,
as compared with 1,093 Bbls per day in 2000. For further information on sales
volumes and product prices, see "Trustee's Discussion and Analysis."

Tight sands gas sales volumes from the underlying properties were 2,104,845 Mcf
in 2001. After reduction of volumes related to production and development costs,
tight sands gas sales volumes allocated to the net profits interests were
1,230,270 Mcf, resulting in a tight sands tax credit for the year of $0.017309
per unit. This credit (or a portion thereof, if units were acquired after
January 2001) is available to be applied against the unitholder's regular
federal income tax liability, subject to certain limitations. Unitholders should
consult their tax advisors regarding use of this credit.

As of December 31, 2001, proved reserves for the net profits interests were
estimated by independent engineers to be 257.3 Bcf of natural gas and 2.1
million Bbls of oil. Estimated gas reserves decreased 31% and oil reserves
decreased 36% from year-end 2000 to 2001, primarily because of the decrease in
year-end realized gas prices from $9.44 to $2.34 per Mcf and West Texas
Intermediate posted oil prices from $23.75 to $16.75 per Bbl, as well as the
resulting decreased allocation of reserves to the net profits interests. All
reserve information prepared by independent engineers has been provided to the
trustee by XTO Energy.

Estimated future net revenues from proved reserves of the net profits interests
at December 31, 2001 are $586.1 million, or $14.65 per unit. Using an annual
discount factor of 10%, the present value of estimated future net revenues at
December 31, 2001 is $293.5 million, or $7.34 per unit. Proved reserve estimates
and related future net revenues have been determined based on year-end oil and
gas prices, as well as other guidelines prescribed by the Financial Accounting
Standards Board as further described under Item 2 of the accompanying Form 10-K.
The present value of estimated future net revenues is not necessarily
representative of the market value of trust units.

As discussed in the tax instructions provided to unitholders in February 2002,
trust distributions are considered portfolio income, rather than passive income.
Unitholders should consult their tax advisors for further information.

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



By:  Ron E. Hooper
     Senior Vice President


                                                                               3
<Page>

THE UNDERLYING PROPERTIES

The underlying properties are predominantly gas-producing properties with
established production histories in the Hugoton area of Oklahoma and Kansas, the
Anadarko Basin of Oklahoma and the Green River Basin of Wyoming. The average
reserve-to-production index for the underlying properties as of December 31,
2001 is approximately 14 years. This index is calculated using total proved
reserves and estimated 2002 production for the underlying properties. Based on
estimated future net revenues at year-end oil and gas prices, the proved
reserves of the underlying properties are approximately 94% natural gas and 6%
oil. XTO Energy operates approximately 90% of the underlying properties.

Because the underlying properties are working interests, production and
development costs are deducted in calculating net profits income. As a result,
net profits income is affected by the level of maintenance and development
activity on the underlying properties. See "Trustee's Discussion and Analysis -
Years Ended December 31, 2001, 2000 and 1999 - Costs." Total 2001 development
costs for the underlying properties were $30,367,276, an increase of 33% from
the prior year. XTO Energy has notified the trustee that total budgeted
development costs for 2002 for the underlying properties are $23.1 million.

HUGOTON AREA

Discovered in 1922, the Hugoton area is the largest natural gas producing area
in North America. During 2001, gas sales volumes from the Hugoton area were
11,257,000 Mcf, or approximately 31% of total sales volumes from the underlying
properties. Most of the production is from the Chase formation at depths of
2,700 to 2,900 feet. XTO Energy 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. XTO Energy has
participated in 3-D seismic shoots covering 30,000 acres of its net acreage
position beneath the Chase formation.

Although increased density drilling was ultimately not approved by the Oklahoma
legislature, Oklahoma regulations were amended in July 1998 to increase
allowable production in the Oklahoma panhandle from 150,000 Mcf per day to
450,000 Mcf per day, which lifted curtailment in this area.

During 2001, development of the Hugoton Area included successful recompletions
to the Towanda Formation. XTO Energy also embarked on a pilot project to test
new restimulation techniques in the Chase intervals. XTO Energy completed 27 of
these restimulations in 2001. During 2002, XTO Energy plans to perform seven
Towanda completions and 46 Chase restimulations.

ANADARKO BASIN

The Anadarko Basin of western Oklahoma was discovered in 1945. Gas sales volumes
from the Anadarko Basin totaled 16,239,000 Mcf in 2001, or approximately 44% of
total sales volumes from the underlying properties. XTO Energy 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.

In Major and Woodward counties, the Mississippian (Osage), Chester and Red Fork
formations were the primary drilling targets in 2001. In Major County, XTO
Energy successfully drilled and (CONTINUED ON NEXT PAGE)

<Table>
<Caption>
-----------------------------------------------------------------------------------------------------------------

ESTIMATED PROVED RESERVES AND FUTURE NET REVENUES

The following are proved reserves of the underlying properties and proved
reserves and future net revenues from proved reserves of the net profits
interests at December 31, 2001, as estimated by independent engineers:


                          Underlying Properties                               Net Profits Interests
                          ---------------------           -------------------------------------------------------
                           Proved Reserves (a)            Proved Reserves (a) (b)          Future Net Revenues
                          ---------------------           -----------------------      From Proved Reserves (a)(c)
                           Gas            Oil              Gas             Oil         ---------------------------
                          (Mcf)          (Bbls)           (Mcf)           (Bbls)       Undiscounted    Discounted
                          -----          ------           -----           ------       ------------    ----------
(IN THOUSANDS)

<S>                      <C>               <C>           <C>                <C>      <C>            <C>
Oklahoma ...........      278,469           3,522         153,563            1,933    $     367,811  $      196,448
Wyoming.............      151,306             244          83,935              136          184,039          78,385
Kansas..............       40,428              52          19,844               27           34,273          18,682
                        ---------      ----------      ----------       ----------    -------------  --------------

     TOTAL..........      470,203           3,818         257,342            2,096    $     586,123  $      293,515
                        =========      ==========      ==========       ==========    =============  ==============
</Table>

(a)   Based on year-end oil and gas prices. For further information regarding
      trust proved reserves, see Item 2 of the accompanying Form 10-K.

(b)   Since the trust has defined net profits interests, the trust does not own
      a specific percentage of the oil and gas reserves. Because trust reserve
      quantities are determined using an allocation formula, any fluctuations in
      actual or assumed prices or costs will result in revisions to the
      estimated reserve quantities allocated to the net profits interests.

(c)   Before income taxes (and the tax benefit of the estimated tight sands tax
      credit) since future net revenues are not subject to taxation at the trust
      level.


                                                                               4
<Page>

completed 13 gross (10.5 net) wells. XTO Energy plans to drill up to six wells
and perform up to 19 workovers in Major County in 2002. In Woodward County, the
Chester Formation with its four separate producing intervals, was the primary
target for 16 gross (13.5 net) wells successfully drilled and completed during
2001. During 2002, XTO Energy plans to drill up to 12 gross (8.3 net) wells and
perform up to six workovers in Woodward County.

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 Cretacious-aged Frontier and Dakota sandstones
at depths ranging from 7,500 to 10,000 feet. Gas sales volumes from the Green
River Basin were 9,101,000 Mcf in 2001, or approximately 25% of total sales
volumes from the underlying properties.

XTO Energy drilled and completed six gross (6.0 net) wells in the Fontenelle
Unit in 2001. Drilling focused on continued 80-acre and 40-acre infill
development of the Frontier sandstones. XTO Energy plans to perform up to six
workovers in the Green River Basin during 2002. XTO Energy may also drill up to
three development wells, depending on gas prices in 2002.

TRUSTEE'S DISCUSSION AND ANALYSIS

YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999

Net profits income for 2001 was $79,272,395, as compared with $56,812,141 for
2000 and $33,139,662 for 1999. The 40% increase in net profits income from 2000
to 2001 was primarily because of higher gas prices, while the 71% increase in
net profits income from 1999 to 2000 was primarily because of higher gas and oil
prices. During 2001, approximately 94%, and in 2000 and 1999, approximately 90%,
of net profits income was derived from natural gas sales.

Trust administration expense was $277,532 in 2001 as compared to $228,211 in
2000 and $95,987 in 1999. Administration expense was lower in 1999, the trust's
initial accounting year, because of costs not billed and paid until 2000.
Increased administration expense from 2000 to 2001 is primarily related to
increased unitholder reporting costs. Interest income was $136,177 in 2001,
$128,150 in 2000 and $46,374 in 1999. Increases in interest income are
attributable to higher net profits income. Distributable income was $79,131,040
or $1.978276 per unit in 2001, $56,712,080 or $1.417802 per unit in 2000 and
$33,090,049 or $0.827253 per unit in 1999.

Net profits income is recorded when received by the trust, which is the month
following receipt by XTO Energy, and generally two months after oil and gas
production. Because of this two-month interval, the trust's initial accounting
year ended December 31, 1999 includes net profits income related to only eleven
months of oil and gas sales, or December 1998 through October 1999 production.
Net profits income is generally affected by three major factors:

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

VOLUMES

From 2000 to 2001, underlying gas sales volumes decreased 1% and underlying oil
sales volumes decreased 2% primarily because natural production decline slightly
exceeded the effects of new wells and workovers. From 1999 to 2000, underlying
gas sales volumes increased 8% and underlying oil sales volumes increased 3%
primarily because of the lag effect of cash receipts in the trust's initial
accounting period, which resulted in less than eleven full months of sales
volumes in 1999.

PRICES

GAS. The 2001 average gas price was $4.30 per Mcf, a 37% increase from the 2000
average gas price of $3.14, which was a 48% increase from the 1999 average gas
price of $2.12 per Mcf. The 1999 average gas price included the effect of adding
$4,977,110 ($3,981,688 net to the trust) to net profits income to achieve a
$2.00 minimum price contractually provided to unitholders for distributions
through March 2000. As of April 2000, there were no longer any minimum price
provisions. See Note 3 to the financial statements. The actual 1999 average
price of $1.96 reflects lower prices caused by high levels of gas remaining in
storage from the abnormally warm winter of 1998-1999. Gas prices began to
increase in May 1999 and, after declining briefly at year end, strengthened in
2000 reaching a record high of $10.10 per MMBtu in December 2000 as winter
demand strained gas supplies. Gas prices declined during 2001 because of fuel
switching due to higher prices, milder weather and a weaker economy which has
reduced the demand for gas and resulted in sharply increased gas storage levels.
The average NYMEX price for January and February 2002 was $2.23 per MMBtu. Gas
prices have risen in March to an average NYMEX price of $2.93 through March 25.
The trust's recent average gas price has been approximately $0.30 per MMBtu
lower than the NYMEX price.

OIL. The average oil price for 2001 was $27.60 per Bbl, 4% lower than the 2000
average oil price of $28.67 per Bbl, which was 73% higher than the 1999 average
price of $16.53 per Bbl. After OPEC members and other oil producers agreed to
production cuts in March 1999, oil prices climbed through the remainder of 1999
and first quarter 2000. Despite OPEC production increases in 2000, increased
demand sustained higher prices. The West Texas Intermediate ("WTI") posted price
reached $34.25 per Bbl in


                                                                               5
<Page>

September 2000, its highest level in ten years. Lagging demand in 2001,
resulting from a worldwide economic slowdown, caused oil prices to decline.
OPEC members agreed to cut daily production by one million barrels in April and
an additional one million barrels in September to adjust for weak demand and
excess supply. The economic decline was accelerated by the terrorist attacks in
the United States on September 11, 2001, placing additional downward pressure
on oil prices. In December, OPEC announced further production cuts of 1.5
million barrels per day effective January 1, 2002, for six months. The average
WTI posted price for January and February 2002 was $17.06. Oil prices have
risen in March to an average WTI posted price of about $21.00 through March 25.
Recent trust oil prices have averaged approximately $2.15 higher than the WTI
posted price.

COSTS

The calculation of net profits income includes deductions for production and
development costs and overhead since the related underlying properties are
working interests. If monthly costs exceed revenues for any state, such excess
costs must be recovered, with accrued interest, from future net proceeds of that
state and cannot reduce net profits income from another state. Costs exceeded
revenues from properties underlying the Wyoming net profits interests in August
1999 because of new wells drilled. All excess costs and accrued interest were
fully recovered in September 1999.

Taxes, transportation and other generally fluctuates with changes in total
revenues. Overhead fluctuates based on changes in the active well count and
drilling activity on the underlying properties, as well as an annual inflation
adjustment.

PRODUCTION. Production expenses increased 11% from 2000 to 2001 because of the
timing of maintenance projects and higher compressor rentals. Production
expenses increased 30% from 1999 to 2000 because of prior period compressor fuel
charges in 2000 and the timing of maintenance projects.

DEVELOPMENT. Development costs were $30,367,276 in 2001, $22,771,150 in 2000 and
$11,596,495 in 1999. The increases are attributable to new wells drilled and
workovers in Oklahoma. Development costs for the calendar year 2001 budget were
higher than the initial estimate of $23 million primarily because of higher
drilling, service, and equipment costs related to demand generated by higher
natural gas prices and carryover of costs from the 2000 budget.

In 2001, development costs deducted from distributions totaled $30.4 million,
compared with actual development costs of $35.2 million. This $4.8 million
excess was almost fully recovered in January and February as the 2002 monthly
budgeted development cost deduction of $1.9 million exceeded actual costs. As of
the March 2002 distribution, cumulative actual development costs exceeded the
amount deducted by $231,000.

OTHER PROCEEDS

Net profits income for 2001 includes proceeds of $307,824 from the sale of
underlying properties in Sweetwater County, Wyoming.

FOURTH QUARTER 2001 AND 2000

During fourth quarter 2001 the trust received net profits income totaling
$8,507,804, compared with fourth quarter 2000 net profits income of $18,291,467.
The 53% decrease in net profits income from fourth quarter 2000 to 2001 was
primarily because of lower product prices partially offset by lower costs.

Administration expense was $42,941 and interest income was $8,217, resulting in
fourth quarter 2001 distributable income of $8,473,080, or $0.211827 per unit.
Distributable income for fourth quarter 2000 was $18,311,880 or $0.457797 per
unit. Distributions to unitholders for the quarter ended December 31, 2001 were:

<Table>
<Caption>
                 Record Date                        Payment Date            Per Unit
           -------------------------           --------------------     ---------------
<S>                                          <C>                       <C>
           October 31, 2001                    November 15, 2001             $ 0.095741
           November 30, 2001                   December 14, 2001               0.071541
           December 31, 2001                   January 15, 2002                0.044545
                                                                        ---------------
                                                                        $      0.211827
                                                                        ===============
</Table>

VOLUMES

Fourth quarter underlying gas sales volumes increased 1% while underlying oil
sales volumes declined 3%. Oil and gas sales volumes fluctuations are primarily
because of the offsetting effects of new wells and natural production decline.

PRICES

The average fourth quarter 2001 gas price was $2.19 per Mcf, or 47% lower than
the fourth quarter 2000 average price of $4.12. The average fourth quarter oil
price was $25.02 per Bbl, or 23% lower than the fourth quarter 2000 average
price of $32.34. For further information about product prices, see "Years Ended
December 31, 2001, 2000 and 1999 - Prices" above.

COSTS

PRODUCTION. Fourth quarter production expenses decreased 35% from 2000 to 2001
because of prior period salt water disposal adjustments recorded in fourth
quarter 2001 and prior period fuel adjustments recorded in fourth quarter 2000.

DEVELOPMENT. Development costs decreased 41% from fourth quarter 2000 to 2001
primarily because of reduced drilling activity in fourth quarter 2001.

For further information about costs, see "Years Ended December 31, 2001, 2000
and 1999 - Costs" above.


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


                                                                               6
<Page>

CALCULATION OF NET PROFITS INCOME

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

<Table>
<Caption>
                                                                                              Three Months
                                          Year Ended December 31 (a)                         Ended December 31(a)
                                ------------------------------------------------       ------------------------------
                                      2001           2000              1999             2001             2000
                                ------------      ------------      ------------       ------------      ------------
<S>                              <C>            <C>            <C>                <C>            <C>
SALES VOLUMES
   Gas (Mcf) (b)
     Underlying properties.....   36,597,937        36,842,156        34,188,398          9,521,295         9,444,893
       Average per day.........      100,268           100,662           102,055            103,492           102,662
     Net profits interests.....   17,671,423        18,199,754        15,583,364          3,627,744         4,568,895

   Oil (Bbls) (b)
     Underlying properties.....      393,731           399,929           388,038             95,063            97,597
       Average per day.........        1,079             1,093             1,158              1,033             1,061
     Net profits interests.....      190,722           198,677           190,668             38,698            47,562

AVERAGE SALES PRICES
   Gas (per Mcf)............... $       4.30      $       3.14      $       2.12       $       2.19      $       4.12
   Oil (per Bbl)............... $      27.60      $      28.67      $      16.53       $      25.02      $      32.34

REVENUES
   Gas sales................... $157,508,999      $115,579,023      $ 72,484,491       $ 20,810,221      $ 38,879,716
   Oil sales...................   10,867,817        11,467,882         6,416,003          2,378,744         3,156,163
                                ------------      ------------      ------------       ------------      ------------
     Total Revenues............  168,376,816       127,046,905        78,900,494         23,188,965        42,035,879
                                ------------      ------------      ------------       ------------      ------------

COSTS
   Taxes, transportation
      and other................   15,694,068        12,023,222         8,264,983          2,078,658         3,855,334
   Production expense (c)......   15,611,725        14,026,261        10,764,476          2,779,198         4,297,168
   Development costs (d).......   30,367,276        22,771,150        11,596,495          5,475,000         9,223,562
   Overhead....................    7,921,077         7,211,096         6,849,712          2,221,354         1,795,481
   Excess costs................         --                --             (35,718)              --                --
   Recovery of excess costs
     and accrued interest......         --                --              35,968               --                --
                                ------------      ------------      ------------       ------------      ------------
     Total Costs...............   69,594,146        56,031,729        37,475,916         12,554,210        19,171,545
                                ------------      ------------      ------------       ------------      ------------

OTHER PROCEEDS
   Property sales..............      307,824              --                --                 --                --
                                ------------      ------------      ------------       ------------      ------------

NET PROCEEDS...................   99,090,494        71,015,176        41,424,578         10,634,755        22,864,334

NET PROFITS PERCENTAGE.........           80%               80%               80%                80%               80%
                                ------------      ------------      ------------       ------------      ------------

NET PROFITS INCOME............. $ 79,272,395      $ 56,812,141      $ 33,139,662       $  8,507,804      $ 18,291,467
                                ============      ============      ============       ============      ============
</Table>


(a)  Because of the two-month interval between time of production and receipt of
     net profits income by the trust: 1) oil and gas sales for the year ended
     December 31, 1999 generally relate to eleven months of production for the
     period December 1998 (the trust's initial month) through October 1999, 2)
     oil and gas sales for the year ended December 31, 2001 and 2000 generally
     relate to twelve months of production for the period November through
     October, and 3) oil and gas sales for the three months ended December 31
     generally relate to production for the period August through October.

(b)  Oil and gas sales volumes are allocated to the net profits interests based
     upon a formula that considers oil and gas prices and the total amount of
     production expenses and development costs. Changes in any of these factors
     may result in disproportionate fluctuations in volumes allocated to the net
     profits interests. Therefore, comparative discussion of oil and gas sales
     volumes is based on the underlying properties.

(c)  During 2001, the costs related to well recompletions and remedial workovers
     were classified as development costs, consistent with their budget
     classification. These costs were previously included in production expense.
     The costs are reclassified in prior periods for consistency with current
     presentation.

(d)  See Note 4 to Financial Statements.


                                                                               7
<Page>

HUGOTON ROYALTY TRUST


STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS

<Table>
<Caption>
                                                                                     December 31
                                                                        -----------------------------------
                                                                              2001              2000
                                                                        ----------------   ----------------
Assets

<S>                                                                     <C>                <C>
  Cash and short-term investments...................................    $      1,781,800   $      5,976,160

  Net profits interests in oil and gas properties - net
    (Notes 1 and 2).................................................         215,346,192        226,081,443
                                                                        ----------------   ----------------

                                                                        $    217,127,992   $    232,057,603
                                                                        ================   ================

Liabilities and Trust Corpus

  Distribution payable to unitholders...............................    $      1,781,800   $      5,976,160

  Trust corpus (40,000,000 units of beneficial interest
    authorized and outstanding).....................................         215,346,192        226,081,443
                                                                        ----------------   ----------------

                                                                        $    217,127,992   $    232,057,603
                                                                        ================   ================
</Table>

STATEMENTS OF DISTRIBUTABLE INCOME

<Table>
<Caption>
                                                                           December 31
                                                      -----------------------------------------------------
                                                            2001             2000                1999
                                                      ---------------   ----------------   ----------------

<S>                                                 <C>               <C>                <C>
Net profits income.................................   $    79,272,395   $     56,812,141   $     33,139,662

Interest income....................................           136,177            128,150             46,374
                                                      ---------------   ----------------   ----------------

  Total income.....................................        79,408,572         56,940,291         33,186,036

Administration expense.............................           277,532            228,211             95,987
                                                      ---------------   ----------------   ----------------

  Distributable income.............................   $    79,131,040   $     56,712,080   $     33,090,049
                                                      ===============   ================   ================

  Distributable income per unit
    (40,000,000 units).............................   $      1.978276   $       1.417802   $       0.827253
                                                      ===============   ================   ================
</Table>


STATEMENTS OF CHANGES IN TRUST CORPUS
<Table>
<Caption>
                                                                     Year Ended December 31
                                                      -----------------------------------------------------
                                                            2001             2000                1999
                                                      ---------------   ----------------   ----------------

<S>                                                   <C>               <C>                <C>
Trust corpus, beginning of year....................   $   226,081,443   $    233,428,609   $    247,067,951

Amortization of net profits interests..............       (10,735,251)        (7,347,166)       (13,638,342)

Return of initial contribution to grantor..........            -                  -                  (1,000)

Distributable income...............................        79,131,040         56,712,080         33,090,049

Distributions declared.............................       (79,131,040)       (56,712,080)       (33,090,049)
                                                      ---------------   ----------------   ----------------

Trust corpus, end of year..........................   $   215,346,192   $    226,081,443   $    233,428,609
                                                      ===============   ================   ================
</Table>

See Accompanying Notes to Financial Statements.


                                                                               8
<Page>

HUGOTON ROYALTY TRUST

NOTES TO FINANCIAL STATEMENTS

1.  TRUST ORGANIZATION AND PROVISIONS

      Hugoton Royalty Trust was created on December 1, 1998 by XTO Energy Inc.
(formerly known as "Cross Timbers Oil Company"). Effective on that date, XTO
Energy conveyed 80% net profits interests in certain predominantly gas-producing
working interest properties in Kansas, Oklahoma and Wyoming to the trust under
separate conveyances for each of the three states. XTO Energy currently owns and
operates the majority of the underlying working interest properties.

      In exchange for the conveyances of the net profits interests to the trust,
40 million units of beneficial interest in the trust were issued to XTO Energy.
On April 8, 1999, XTO Energy sold 15 million units in the trust's initial public
offering. On May 7, 1999, XTO Energy sold an additional 2 million units pursuant
to the underwriters' overallotment option. In 1999 and 2000, XTO Energy sold 1.3
million units to certain of its officers. The trust did not receive any proceeds
from the sale of trust units.

      Bank of America, N.A. is the trustee for the trust. The trust indenture
provides, among other provisions, that:

      -    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 may dispose of all or part of the net profits interests if
           approved by 80% of the unitholders, or upon trust termination.
           Otherwise, the trust may sell up to 1% of the value of the net
           profits interests in any calendar year, pursuant to notice from XTO
           Energy of its desire to sell the related underlying properties. Any
           sale must be for cash with the proceeds promptly distributed to the
           unitholders;
      -    the trustee may establish a cash reserve for payment of any
           liability that is contingent or not currently payable;
      -    the trustee may borrow funds to pay trust liabilities if repaid in
           full prior to further distributions to unitholders;
      -    the trustee will make monthly cash distributions to unitholders
           (Note 3); and
      -    the trust will terminate upon the first occurrence of:
           -     disposition of all net profits interests pursuant to terms of
                 the trust indenture,
           -     gross proceeds from the underlying properties falling below $1
                 million per year for two successive years, or
           -     a vote of 80% of the unitholders to terminate the trust in
                 accordance with provisions of the trust indenture.

2.  BASIS OF ACCOUNTING

      The financial statements of the trust are prepared on the following basis
and are not intended to present financial position and results of operations in
conformity with generally accepted accounting principles:

      -     Net profits income is recorded in the month received by the trustee
            (Note 3).
      -     Trust expenses are recorded based on liabilities paid and cash
            reserves established by the trustee for liabilities and
            contingencies.
      -     Distributions to unitholders are recorded when declared by the
            trustee (Note 3).

      The most significant differences between the trust's financial statements
and those prepared in accordance with generally accepted accounting principles
are:

      -     Net profits income is recognized in the month received rather than
            accrued in the month of production.
      -     Expenses are recognized when paid rather than when incurred.
      -     Cash reserves may be established by the trustee for contingencies
            that would not be recorded under generally accepted accounting
            principles.

      The initial carrying value of the net profits interests of $247,066,951
was XTO Energy's historical net book value of the interests on December 1, 1998,
the date of the transfer to the trust. Amortization of the net profits interests
is calculated on a unit-of-production basis and charged directly to trust
corpus. Accumulated amortization was $31,720,759 as of December 31, 2001 and
$20,985,508 as of December 31, 2000.


3.  DISTRIBUTIONS TO UNITHOLDERS

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

      Net profits income received by the trustee consists of net proceeds
received in the prior month by XTO Energy from the underlying properties,
multiplied by 80%. Net proceeds are the gross proceeds received from the sale of
production, less costs. Costs generally include applicable taxes,
transportation, legal and marketing charges, production costs, development and
drilling costs, and overhead (Note 6).

      For monthly trust distributions declared through March 2000, the related
net profits income was based on gross proceeds equal to the greater of:

      -    the actual amount received from sales of production, or
      -    the imputed amount that would be received from sales of production at
           a gas price of $2.00 per Mcf. For the year ended December 31, 1999,
           imputed proceeds based on a $2.00 gas price exceeded actual proceeds
           by $4,977,110 ($3,981,688 net to the trust). For the year ended
           December 31, 2000, there were no imputed proceeds because actual gas
           prices were higher than the $2.00 price support.

      XTO Energy, as owner of the underlying properties, computes net profits
income separately for each of the three conveyances (Note 1). If costs exceed
revenues for any conveyance, such excess costs must be recovered, with accrued
interest, from future net proceeds of that conveyance and cannot reduce net
profits income from the other conveyances.


                                                                               9
<Page>

4.  DEVELOPMENT COSTS

      For the year ended December 31, 2001, XTO Energy deducted development
costs of $30.4 million, compared with actual development costs of $35.2 million.
This $4.8 million excess was almost fully recovered in January and February as
the 2002 monthly budgeted development cost deduction of $1.9 million exceeded
actual costs. As of the March 2002 distribution, cumulative actual development
costs exceed the amount deducted by $231,000.

5.  FEDERAL INCOME TAXES

      Tax counsel has advised the trust that, under current tax laws, the trust
will be classified as a grantor trust for federal income tax purposes and,
therefore, is not subject to taxation at the trust level. However, the opinion
of tax counsel is not binding on the Internal Revenue Service.

      For federal income tax purposes, unitholders of a grantor trust are
considered to own the trust's income and principal as though no trust were in
existence. The income of the trust is deemed to be received or accrued by the
unitholders at the time such income is received or accrued by the trust, rather
than when distributed by the trust.

      XTO Energy has advised the trustee that the trust receives net profits
income from tight sands gas wells. Production sold through 2002 from wells
drilled on the underlying properties 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), qualifies for the
federal income tax credit for producing nonconventional fuels under Section 29
of the Internal Revenue Code.

      This tax credit was approximately $0.52 per MMBtu and $0.017309 per unit
in 2001, $0.014499 per unit in 2000 and $0.016093 per unit in 1999. The credit
is recalculated annually based on each year's qualifying production through the
year 2002. Unitholders should consult their tax advisors regarding use of this
credit and other trust tax compliance matters.

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

6.  XTO ENERGY INC.

      XTO Energy operates approximately 90% of the wells on the underlying
properties. In computing net proceeds, XTO Energy deducts an overhead charge for
reimbursement of administrative expenses on the underlying properties it
operates. As of December 31, 2001, the overhead charge was approximately
$678,000 ($542,400 net to the trust) per month and is subject to annual
adjustment based on an oil and gas industry index. As of March 1, 2002, XTO
Energy owned 54.3% of the trust.

      XTO Energy sells a significant portion of natural gas production from the
underlying properties to certain of XTO Energy's wholly owned subsidiaries under
contracts in existence when the trust was created, generally at amounts
approximating monthly published market prices. Most of the production from the
Hugoton area is sold under a contract to Timberland Gathering & Processing
Company, Inc. ("TGPC"). Much of the gas production in Major County, Oklahoma is
sold to Ringwood Gathering Company ("RGC"), which retains a $0.315 per Mcf
compression and gathering fee. TGPC and RGC sell gas to Cross Timbers Energy
Services, Inc. ("CTES"), which markets gas to third parties. XTO Energy sells
directly to CTES most gas production not sold directly to TGPC or RGC.

      Total gas sales from the underlying properties to XTO Energy's wholly
owned subsidiaries were $128.5 million for the year ended December 31, 2001, or
82% of total gas sales, $89.0 million for the year ended December 31, 2000, or
77% of total gas sales, and $55.9 million for the year ended December 31, 1999,
or 77% of total gas sales.

7.  LITIGATION

      XTO Energy is a defendant in two separate lawsuits that could, if
adversely determined, decrease future trust distributable income. Any damages
relating to production prior to the formation of the trust will be borne by XTO
Energy.

      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, XTO Energy 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. No class has been
certified. The court has ordered that the parties enter mediation, which should
occur in the first half of 2002. XTO Energy believes that it has strong defenses
to this lawsuit and intends to vigorously defend its position. However, if XTO
Energy ultimately makes any payments, the trust will bear its 80% share of such
payments 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 XTO Energy 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


                                                                              10
<Page>

action alleges that XTO Energy underpaid royalties on natural gas produced from
federal leases and lands owned by Native Americans by at least 20% during the
past ten 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 XTO Energy to
cease the allegedly improper measuring practices. The cases against XTO Energy
and other defendants have been consolidated in the United States District Court
for Wyoming. While XTO Energy is unable to predict the outcome of this case or
estimate the amount of any possible loss, it 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 XTO Energy management's opinion, is
not currently expected to be material to the trust's annual distributable
income, financial position or liquidity.

      In June 2001, XTO Energy was served with a third lawsuit styled Quinque
Operating Co., et al. v. Gas Pipelines, et al. The action was filed in the
District Court of Stevens County, Kansas, against XTO Energy and one of its
subsidiaries, along with over 200 natural gas transmission companies, producers,
gatherers and processors of natural gas. Plaintiffs sought to represent a class
of plaintiffs consisting of all similarly situated royalty owners, overriding
royalty owners and working interest owners either from whom defendants had
purchased natural gas or who received economic benefit from the sale of such gas
since January 1, 1974. The complaint alleged that the defendants had mismeasured
both the volume and heating content of natural gas delivered into their
pipelines resulting in underpayments to plaintiffs. The plaintiffs dismissed XTO
Energy and its subsidiary as a defendant and substituted another subsidiary of
XTO Energy as a defendant. Any potential liability of the subsidiary will not
affect the trust's net proceeds.

      For further information regarding these lawsuits and other legal
proceedings pertaining to the trust, see Item 3 of the trust's Annual Report on
Form 10-K included in this report.

8.  SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED)

      Proved oil and gas reserve information is included in Item 2 of the
trust's Annual Report on Form 10-K included in this report.

9.  QUARTERLY FINANCIAL DATA (UNAUDITED)

      The following is a summary of net profits income, distributable income and
distributable income per unit by quarter for 2001 and 2000:

<Table>
<Caption>
                                                              Distributable
                       Net Profits        Distributable          Income
                         Income              Income              Per Unit
                       -----------         -----------         ------------

<S>                    <C>                 <C>                 <C>
2001
----
First Quarter......... $33,683,872         $33,654,480         $   0.841362
Second Quarter........  21,720,948          21,731,640             0.543291
Third Quarter.........  15,359,771          15,271,840             0.381796
Fourth Quarter........   8,507,804           8,473,080             0.211827
                       -----------         -----------         ------------
                       $79,272,395         $79,131,040         $   1.978276
                       ===========         ===========         ============


2000
----
First Quarter......... $10,981,680         $10,939,280         $   0.273482
Second Quarter........  11,288,646          11,264,480             0.281612
Third Quarter.........  16,250,348          16,196,440             0.404911
Fourth Quarter........  18,291,467          18,311,880             0.457797
                       -----------         -----------         ------------
                       $56,812,141         $56,712,080         $   1.417802
                       ===========         ===========         ============
</Table>


                                                                              11
<Page>

REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS

BANK OF AMERICA, N.A., AS TRUSTEE FOR THE HUGOTON ROYALTY TRUST:

    We have audited the accompanying statements of assets, liabilities and trust
corpus of the Hugoton Royalty Trust as of December 31, 2001 and 2000, and the
statements of distributable income and changes in trust corpus for each of the
years then ended. These financial statements are the responsibility of the
trustee. Our responsibility is to express an opinion on these financial
statements based on our audits.

    We conducted our audits in accordance with auditing standards generally
accepted in the United States. Those standards require that we plan and perform
the audit to obtain reasonable assurance about whether the financial statements
are free of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements. An
audit also includes assessing the accounting principles used and significant
estimates made by the trustee, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.

    As described in Note 2 to the financial statements, these financial
statements were prepared on the modified cash basis of accounting, which is a
comprehensive basis of accounting other than accounting principles generally
accepted in the United States.

    In our opinion, the financial statements referred to above present fairly,
in all material respects, the assets, liabilities and trust corpus of the trust
as of December 31, 2001 and 2000 and its distributable income and changes in
trust corpus for each of the years then ended, in conformity with the modified
cash basis of accounting described in Note 2.


ARTHUR ANDERSEN LLP

Fort Worth, Texas
March 19, 2002


                                                                              12
<Page>

HUGOTON ROYALTY TRUST

901 Main Street, 17th Floor
P.O. Box 830650
Dallas, Texas 75283-0650
(877) 228-5083
Bank of America, N.A., Trustee

A copy of the Hugoton Royalty Trust Form 10-K has been provided with this Annual
Report. Additional copies of this Annual Report and Form 10-K will be provided
to unitholders without charge upon request. Copies of exhibits to the Form 10-K
may be obtained upon request.

AUDITORS

Arthur Andersen LLP
Fort Worth, Texas

LEGAL COUNSEL

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

TAX COUNSEL

Winstead Sechrest & Minick P.C.
Houston, Texas

TRANSFER AGENT AND REGISTRAR

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