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SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

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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, 2002 |  | Commission file number 1-10476
|------------------------------------------- |  | ------------------------------

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

Texas

58-6379215(State or other jurisdiction of

(I.R.S. Employerincorporation or organization)

Identification No.)Bank of America, N.A.

75283-0650Trustee

(Zip Code)P.O. Box 830650Dallas, 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 registeredUnits 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.    [  ]

Indicate by check mark whether the registrant is an accelerated filer (as defined in
Rule 12b-2 of the Securities Exchange Act of 1934). Yes    [X]    No    [  ]

The aggregate market value of the units of beneficial interest of the trust, based on the closing price on
the New York Stock Exchange as of June 28, 2002 (the last business day of its most recently completed second fiscal quarter), held by non-affiliates of the registrant on that date
was approximately $194 million.

At March 3, 2003, there were 40,000,000 units of beneficial interest of the trust outstanding.

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:

2002 Annual Report to UnitholdersPart II

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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 XTO Energy Inc., 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).

The
trust's internet web site is www.hugotontrust.com. As of March 31, 2003, we make available free of charge, through our web site, our annual report on
Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and all amendments to those reports filed or furnished pursuant to
Section 13(a) or 15(d) of the Securities Exchange Act of 1934. These reports are accessible through our internet web site as soon as reasonably practicable after we electronically file such
material with, or furnish it to, the Securities and Exchange Commission.

Effective
December 1, 1998, XTO Energy (formerly known as Cross Timbers Oil Company) conveyed to the trust 80% net profits interests in certain predominantly natural gas producing
working interest properties in Kansas, Oklahoma and Wyoming under three separate conveyances. In exchange for these net profits interest conveyances to the trust, 40 million units of beneficial
interest were issued to XTO Energy. In April and May 1999, XTO Energy sold a total of 17 million units in the trust's initial public offering. In 1999 and 2000, XTO Energy also sold
1.3 million trust units to certain of its officers. The trust did not receive any proceeds from these sales of trust units. As of March 3, 2003, XTO Energy owned 21,705,893 units in the
trust. Units are listed and traded on the New York Stock Exchange under the symbol "HGT."

The
net profits interests entitle the trust to receive 80% of net proceeds from the sale of oil and gas from the underlying properties. Each month XTO Energy determines the amount of
cash received from the sale of production and deducts property and production taxes, development and production costs and overhead. For trust distributions declared through March 2000, net
proceeds from the sale of gas
related to those distributions were contractually required to be computed differently. Net proceeds for this period were computed monthly based on the greater of either a realized price of $2.00 per
Mcf or the actual price received by XTO Energy 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 oil and gas in the prior month. If monthly costs exceed
revenues for any of the three conveyances (one for each of the states of Kansas, Oklahoma, and Wyoming), such excess costs must be recovered, with accrued interest, from future net proceeds of that
conveyance and cannot reduce net proceeds from other conveyances.

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

To
the extent it has the right to do so, XTO Energy is responsible for marketing its production from the underlying properties under existing sales contracts or new arrangements on the
best terms reasonably obtainable in the circumstances. See Item 2., "Pricing and Sales Information."

Net
profits income received by the trust on or before the last business day of the month is related to net proceeds received by XTO Energy 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



Subtracting



1

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

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

The
trustee's function is to collect the net profits income from the net profits interests, to pay all trust expenses, and pay the monthly distribution amount to unitholders. The
trustee's powers are specified by the terms of the 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
91% of the net profits income received by the trust during 2002, as well as 94% of the estimated proved reserves of the net profits interests at December 31, 2002
(based on estimated future net cash flows 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 XTO Energy 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.



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. During 2002, sales volumes from the
underlying properties in the Hugoton area averaged approximately 28,500 Mcf of gas per day and 77 Bbls of oil per day.

Most
of the production from the underlying properties in the Hugoton area is from the Chase formation, at depths of 2,700 to 2,900 feet. XTO Energy has informed the trustee that it plans
to develop other formations that underlie the 79,500 net acres held by production by the Chase formation wells, including 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. XTO Energy has participated in 3-D seismic shoots covering 30,000 acres of XTO Energy's
net acreage position beneath the Chase formation. Test wells were drilled to delineate the Council Grove formation in 1999, 2000 and 2001.

During
2002, development of the Hugoton area included four successful recompletions to the Towanda formation. XTO Energy also continued its restimulation program in the Chase intervals,
completing 33 of these restimulations in 2002. During 2003, XTO Energy plans to perform 35 Chase restimulations.

2

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XTO
Energy's future development plans for the underlying properties in the Hugoton area include:



XTO
Energy delivers most of its Hugoton gas production to a gathering and processing system operated by a subsidiary. This system collects approximately 75% of its throughput from
underlying properties, which, in recent months, has been approximately 22,500 Mcf per day from 270 wells. The gathering subsidiary purchases the gas from XTO Energy at the wellhead, gathers and
transports the gas to its plant, and treats and processes the gas at the plant. The gathering subsidiary pays XTO Energy for wellhead volumes at a price of 80% to 85% of the residue price received
upon sale to XTO Energy's marketing affiliate. Under long-term contracts, the gathering subsidiary sells residue volumes to XTO Energy's marketing affiliate at a price equal to a published
index 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 $0.015 per MMBtu.

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



Oil and gas were discovered in the Anadarko Basin of western Oklahoma in 1945. Daily sales volumes from the underlying properties in the Anadarko Basin averaged
42,100 Mcf and 845 Bbls in 2002. 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.

The
fields in the Major County area are characterized by oil and 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.

In
Major and Woodward counties, the Mississippian (Osage), Chester and Red Fork formations were the primary drilling targets in 2002. In Major County, XTO Energy successfully drilled
seven gross (4.9 net) wells. XTO Energy plans to drill up to six wells and perform up to 11 workovers in Major County during the next year. In Woodward County, the Chester formation, with its four
separate producing intervals, was the primary target for ten gross (8.0 net) wells successfully drilled and completed during 2002. During 2003, XTO Energy plans to drill up to 12 gross (11.5 net)
wells and perform up to five workovers in Woodward County.

XTO
Energy plans to further develop the underlying properties in the Major County area primarily through:



3

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A
gathering subsidiary of XTO Energy 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 XTO Energy and other producers in the area under various agreements including life-of-production contracts. The gathering subsidiary
gathers and transports the gas to a third-party processor, which processes the gas and pays XTO Energy and other producers for at least 50% of the liquids processed. After the gas is processed, the
gathering subsidiary transports the gas via a residue pipeline to a connection with an interstate pipeline. The gathering subsidiary sells the residue gas to the marketing subsidiary of XTO Energy
based upon the average price of several published indices. The gathering subsidiary pays this price to XTO Energy less a compression and gathering fee of approximately $0.31 per Mcf of residue gas.
This gathering fee was previously approved by the Federal Energy Regulatory Commission when the gathering subsidiary was regulated. During 2002, the gathering system collected approximately 19,500 Mcf
per day from over 400 wells, 70% of which XTO Energy 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 8,300 Mcf per day from 61 wells, for a historical average fee of approximately $0.12 per Mcf.

XTO
Energy also sells gas to its marketing subsidiary, which then sells the gas to third parties. The price paid to XTO Energy 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.



The Green River Basin is located in southwestern Wyoming. Natural gas was discovered in the Fontenelle Field of the Green River Basin in the early 1970s. The
producing reservoirs are the Cretaceous-aged Frontier, Baxter and Dakota sandstones at depths ranging from 7,500 to 10,000 feet.

In
2002, daily sales volumes from the underlying properties in the Fontenelle Field averaged 23,400 Mcf of natural gas and 46 Bbls of oil. XTO Energy has informed the trustee that its
development activities in the Fontenelle Field were delayed for the better part of 2002 due to the pipeline limitations and price volatility. XTO Energy plans to perform up to five workovers and may
drill up to five wells in the Green River Basin during 2003.

Potential
development activities for the underlying properties in this area include:



XTO
Energy markets the gas produced from the Fontenelle Unit and nearby properties under three different marketing arrangements. Under the agreement covering 70% of the gas sold, XTO
Energy 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 XTO Energy and sold to XTO Energy's marketing subsidiary. The
owner of the gas plant and related pipeline charges XTO Energy for operational fuel and processing. In 2002, the fuel charge was 0.025% of the volumes produced and the processing fee was $0.051 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 XTO Energy. The marketing subsidiary does not receive a
marketing fee. The gas not sold under the above arrangement is sold either under a similar arrangement where the fee is $0.148 per MMBtu, or under a contract where XTO Energy directly sells the gas to
a third party on the lease at an adjusted index price. Condensate is sold at the lease to an independent third party at market rates.

4

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Producing Acreage and Well Counts

For the following data, "gross" refers to the total wells or acres on the underlying properties in which XTO Energy owns a working interest and "net" refers to
gross wells or acres multiplied by the percentage working interest owned by XTO Energy. Although many of XTO Energy's 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, 2002. Undeveloped acreage is not significant.

Gross

NetHugoton Area

216,790

199,590Anadarko Basin

152,042

113,946Green River Basin

39,155

26,899Total

407,987

340,435


The
following is a summary of the producing wells on the underlying properties as of December 31, 2002:

Operated
Wells

Nonoperated
Wells

TotalGross

Net

Gross

Net

Gross

NetGas

1,088

989.5

270

62.8

1,358

1,052.3Oil

126

113.7

7

1.7

133

115.4Total

1,214

1,103.2

277

64.5

1,491

1,167.7


The
following is a summary of the number of wells drilled on the underlying properties during the years indicated. Unless otherwise indicated, all wells drilled are developmental. There
were two gross (0.7 net) wells in process of drilling at December 31, 2002.

2002

2001

2000Gross

Net

Gross

Net

Gross

NetCompleted gas wells (a)

24

15.4

46

34.1

40

31.0Completed oil wells (b)









1

0.1Total

24

15.4

46

34.1

41

31.1


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5

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Oil and Gas Production

Trust production is recognized in the period net profits income is received, which is the month following receipt by XTO Energy, and generally two months after
the time of production. Oil and gas
production and average sales prices attributable to the underlying properties and the net profits interests for the three years ended December 31, 2002 were as follows:

2002

2001

2000ProductionUnderlying PropertiesGasSales (Mcf)

34,315,145

36,597,937

36,842,156Average per day (Mcf)

94,014

100,268

100,662OilSales (Bbls)

353,185

393,731

399,929Average per day (Bbls)

968

1,079

1,093Net Profits InterestsGasSales (Mcf)

11,774,205

17,671,423

18,199,754Average per day (Mcf)

32,258

48,415

49,726OilSales (Bbls)

123,142

190,722

198,677Average per day (Bbls)

337

523

543Average Sales PriceGas (per Mcf)

$  2.44

$  4.30

$  3.14Oil (per Bbl)

$23.70

$27.60

$28.67


Oil and Natural Gas Reserves



Miller and Lents, Ltd., independent petroleum engineers, has estimated oil and gas reserves attributable to the underlying properties as of
December 31, 2002, 2001, 2000 and 1999. The estimated reserves for the underlying properties are then used by XTO Energy to calculate the estimated oil and gas reserves attributable to the net
profits interests. Numerous uncertainties are inherent in estimating reserve volumes and values, and such estimates are subject to change as additional information becomes available. The reserves
actually recovered and the timing of production of these reserves may be substantially different from the original estimates.

Reserve
quantities and revenues for the net profits interests were estimated from projections of reserves and revenues attributable to the combined interests of the trust and XTO Energy
in the subject properties. Since the trust has defined net profits interests, the trust does not own a specific percentage of the oil and gas reserve quantities. Accordingly, reserves allocated to the
trust pertaining to its 80% net profits interests 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
cash flows are not subject to taxation at the trust level.

6

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Year-end
weighted average realized gas prices used to determine the standardized measure were $4.37 per Mcf in 2002, $2.34 per Mcf in 2001, $9.44 per Mcf in 2000 and $2.23
per Mcf in 1999. Year-end oil prices used to determine the standardized measure were based on a West Texas Intermediate crude oil posted price of $28.00 per Bbl in 2002, $16.75 per Bbl in
2001, $23.75 per Bbl in 2000 and $22.75 per Bbl in 1999.



|(in thousands)             |                                             | Underlying Properties |         | Net Profits
Interests |     
|-------------------------- | ------------------------------------------- | --------------------- | ------- | --------------------- | ----
|
|Balance, December 31, 1999 |                                             | 505,369               |         | 4,271                 |     
|                           | Extensions, discoveries and other additions |                       | 29,076  |                       | 132 
|                           | Revisions of prior estimates                |                       | 17,640  |                       | 544 
|                           | Property sales                              |                       | (225    | )                     | (10 
|                           | Productionsales volumes                    |                       | (36,842 | )                     | (400
|                           |                                             |                       |         |                       |     
|Balance, December 31, 2000 |                                             | 515,018               |         | 4,537                 |     
|                           | Extensions, discoveries and other additions |                       | 18,365  |                       | 65  
|                           | Revisions of prior estimates                |                       | (26,582 | )                     | (390
|                           | Productionsales volumes                    |                       | (36,598 | )                     | (394
|                           |                                             |                       |         |                       |     
|Balance, December 31, 2001 |                                             | 470,203               |         | 3,818                 |     
|                           | Extensions, discoveries and other additions |                       | 12,076  |                       | 117 
|                           | Revisions of prior estimates                |                       | 28,582  |                       | 531 
|                           | Property sales                              |                       | (45     | )                     | (2  
|                           | Productionsales volumes                    |                       | (34,315 | )                     | (353
|                           |                                             |                       |         |                       |     
|Balance, December 31, 2002 |                                             | 476,501               |         | 4,111                 |     
|                           |                                             |                       |         |                       |     

Extensions,
discoveries and additions in 2000, 2001 and 2002 are primarily related to delineation of additional proved undeveloped reserves in the Anadarko Basin. Revisions of prior
estimates of the proved reserves for the underlying properties in each year are primarily because of changes in the year-end gas price. Higher upward and downward revisions for the net
profits interests as compared with the underlying properties in each year were caused by changes in the year-end gas price which resulted in increased gas reserves allocated to or from the
trust.



|(in thousands)    |  | Underlying Properties |  | Net Profits Interests
|----------------- |  | --------------------- |  | ---------------------
|
|December 31, 1999 |  | 431,399               |  | 3,595                
|                  |  |                       |  |                      
|December 31, 2000 |  | 434,904               |  | 3,935                
|                  |  |                       |  |                      
|December 31, 2001 |  | 401,846               |  | 3,297                
|                  |  |                       |  |                      
|December 31, 2002 |  | 407,959               |  | 3,580                
|                  |  |                       |  |                      

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|(in thousands)          |             | December 31
|----------------------- | ----------- | -----------
|
|Underlying Properties   |             |            
|Future cash inflows     |             | $          
|Future costs:           |             |            
|                        | Production  |            
|                        | Development |            
|                        |             |            
|Future net cash flows   |             |            
|10% discount factor     |             |            
|                        |             |            
|Standardized measure    |             | $          
|                        |             |            
|Net Profits Interests   |             |            
|Future cash inflows     |             | $          
|Future production taxes |             |            
|                        |             |            
|Future net cash flows   |             |            
|10% discount factor     |             |            
|                        |             |            
|Standardized measure    |             | $          
|                        |             |            

8

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|(in thousands)                                               |                            |               |         |         |         |            |           
|------------------------------------------------------------ | -------------------------- | ------------- | ------- | ------- | ------- | ---------- | ----------
|
|Underlying Properties                                        |                            |               |         |         |         |            |           
|Standardized measure, January 1                              |                            | $             | 366,894 |         | $       | 1,940,362  |           
|                                                             |                            |               |         |         |         |            |           
|Revisions:                                                   |                            |               |         |         |         |            |           
|                                                             | Prices and costs           |               |         | 387,989 |         |            | (1,626,755
|                                                             | Quantity estimates         |               |         | 16,136  |         |            | (2,367    
|                                                             | Accretion of discount      |               |         | 32,022  |         |            | 166,273   
|                                                             | Future development costs   |               |         | (20,105 | )       |            | (20,415   
|                                                             | Production rates and other |               |         | (47     | )       |            | 362       
|                                                             |                            |               |         |         |         |            |           
|                                                             |                            | Net revisions |         |         | 415,995 |            |           
|Extensions, additions and discoveries                        |                            |               | 16,467  |         |         | 8,524      |           
|Production                                                   |                            |               | (60,151 | )       |         | (129,457   | )         
|Development costs                                            |                            |               | 22,733  |         |         | 30,367     |           
|Sales in place                                               |                            |               | (52     | )       |         |           |           
|                                                             |                            |               |         |         |         |            |           
|                                                             |                            | Net change    |         |         | 394,992 |            |           
|                                                             |                            |               |         |         |         |            |           
|Standardized measure, December 31                            |                            | $             | 761,886 |         | $       | 366,894    |           
|                                                             |                            |               |         |         |         |            |           
|Net Profits Interests                                        |                            |               |         |         |         |            |           
|Standardized measure, January 1                              |                            | $             | 293,515 |         | $       | 1,552,289  |           
|Extensions, discoveries and other additions                  |                            |               | 13,173  |         |         | 6,819      |           
|Accretion of discount                                        |                            |               | 25,618  |         |         | 133,018    |           
|Revisions of prior estimates, changes in price and other (a) |                            |               | 307,178 |         |         | (1,319,339 | )         
|Property sales                                               |                            |               | (41     | )       |         |           |           
|Net profits income                                           |                            |               | (29,934 | )       |         | (79,272    | )         
|                                                             |                            |               |         |         |         |            |           
|Standardized measure, December 31                            |                            | $             | 609,509 |         | $       | 293,515    |           
|                                                             |                            |               |         |         |         |            |           

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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.



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

9

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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.



The Minerals Management Service of the United States Department of the Interior continues to evaluate 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 a change in the final rules could cause an increase in the federal royalties to be paid on these properties, and, correspondingly, decrease the revenue to XTO Energy and the trust,
XTO Energy's management does not believe that any rule changes will have a significant detrimental effect on trust distributions.

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



The trust receives net profits 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.

Congress
has considered extending this credit beyond the December 31, 2002 expiration date, and the creation of similar new tax credits. Unless new legislation is passed,
extending this credit on existing eligible production or allowing for credits on new production, there will be no further benefit on production past the year 2002.

Pricing and Sales Information

A subsidiary of XTO Energy purchases most of XTO Energy's natural gas production at the monthly published index price, then sells the gas to third parties for the
best available price. Any marketing gains or losses are not included in trust net proceeds. Oil production is generally marketed at the wellhead to third parties at the best available price. XTO
Energy 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 Ringwood area of 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 XTO Energy's marketing subsidiary, it may charge XTO Energy 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.

10

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Item 3.Legal Proceedings

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, formerly known as Cross Timbers Oil Company, 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 parties have entered into a settlement agreement under which the trust's portion of the settlement will be approximately
$850,000, or 2.1 cents per unit. This amount reflects the trust's 80% share of the settlement relating to production from the underlying properties for periods since December 1, 1998. The court
has tentatively approved the settlement, subject to a fairness hearing in April 2003 and approval of the court. Assuming that no appeal is filed, and based on XTO Energy's anticipated
settlement payment date of July 2003, this amount will reduce the trust's August 2003 distribution, which is paid to unitholders in September. The effect of the settlement on future
distributions for other months will not be significant.

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 XTO Energy underpaid royalties on natural gas produced from federal leases and lands owned by Native Americans in amounts in excess
of 20% as a result of mismeasuring the volume of natural gas and wrongfully analyzing its heating content during at least the past ten years. The suit, which was brought under the qui tamprovisions 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 has informed the trustee
that 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.

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

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

No matters were submitted to a vote of unitholders during 2002.

11

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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, 2002 is
incorporated herein by reference.

Item 6.Selected Financial Data

Year Ended December 312002

2001

2000

1999Net Profits Income

$
29,934,195

$
79,272,395

$
56,812,141

$
33,139,662Distributable Income


29,572,360


79,131,040


56,712,080


33,090,049Distributable Income per Unit


0.739309


1.978276


1.417802


0.827253Distributions per Unit


0.739309


1.978276


1.417802


0.827253Total Assets at Year-End


208,721,083


217,127,992


232,057,603


237,980,449


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

The "Trustee's Discussion and Analysis" of financial condition and results of operations for the three-year period ended December 31, 2002 on
pages 5 and 6 of the trust's Annual Report to unitholders for the year ended December 31, 2002 is incorporated herein by reference.

Liquidity and Capital Resources

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

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

Contractual Obligations and Commitments

The trust had no obligations and commitments to make future contractual payments as of December 31, 2002, other than the December distribution payable to
unitholders in January 2003, as reflected in the
statement of assets, liabilities and trust corpus. The trust has not guaranteed the debt of any other party, nor does the trust have any other arrangements or relationships with other entities that
could potentially result in unconsolidated debt. Additionally, the trust has no off balance sheet financing arrangements.

Related Party Transactions

The underlying properties from which the net profits interests were carved are currently owned by XTO Energy, which operates approximately 94% of the underlying
properties. In computing net proceeds, XTO Energy deducts a monthly overhead charge for reimbursement of administrative expenses on the underlying properties it operates. As of December 31,
2002, the monthly overhead charge was approximately $720,000 ($576,000 net to the trust) and is subject to annual adjustment based on an oil and gas industry index. As of March 3, 2003, XTO
Energy owned 21,705,893, or 54.3%, of the 40,000,000 outstanding units.

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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. For further information regarding natural gas sales from the underlying properties to affiliates of XTO Energy,
see Item 2, Properties, and Note 6 to Financial Statements in the trust's Annual Report to unitholders for the year ended December 31, 2002. Total gas sales from the underlying
properties to XTO Energy's wholly owned subsidiaries were $59.1 million for the year ended December 31, 2002, or 71% of total gas sales, $128.5 million for the year ended
December 31, 2001, or 82% of total gas sales and $89.0 million for the year ended December 31, 2000, or 77% of total gas sales.

Critical Accounting Policies

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



The trust's financial statements are prepared on a modified cash basis, which is a comprehensive basis of accounting other than generally accepted accounting
principles. This method of accounting is
consistent with reporting of taxable income to trust unitholders. The most significant differences between the trust's financial statements and those prepared in accordance with generally accepted
accounting principles are:



For
further information regarding the trust's basis of accounting, see Note 2 to Financial Statements in the trust's Annual Report to unitholders for the year ended
December 31, 2002.

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



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

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

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Forward-Looking Statements

Certain information included in this annual report and other materials filed, or to be filed, by the trust with the Securities and Exchange Commission (as well as
information included in oral statements or other written statements made or to be made by XTO Energy or the trustee) contain forward-looking statements within the meaning of Section 21E of the
Securities Exchange Act of 1934, as amended, and Section 27A of the Securities Act of 1933, as amended, relating to the trust operations of the underlying properties and the oil and gas
industry. Such forward-looking statements may concern, among other things, development activities, maintenance projects, development, production and other costs, oil and gas prices, pricing
differentials, proved reserves, production levels, litigation, regulatory matters and competition. Such forward-looking statements are based on XTO Energy's current plans, expectations, assumptions,
projections and estimates and are identified by words such as "expects," "intends," "plans," "projects," "anticipates," "predicts," "believes," "goals," "estimates," "should," "could", and similar
words that convey the uncertainty of future events. These statements are not guarantees of future performance and involve certain risks, uncertainties and assumptions that are difficult to predict.
Therefore, actual results may differ materially from expectations, estimates or assumptions expressed in, implied in, or forecasted in such forward-looking statements. Some of the risk factors that
could cause actual results to differ materially are discussed below.

Oil and Gas Price Fluctuations.The trust's monthly cash distributions are highly dependent upon the prices realized from the
sale of gas and, to a lesser extent, oil. Oil and gas prices can fluctuate widely on a month-to-month basis in response to a variety of factors that are beyond the control of
the trust and XTO Energy. Factors that contribute to price fluctuations include instability in oil-producing regions, worldwide economic conditions, weather conditions, the supply and
price of foreign oil and gas, consumer demand, and the price and availability of alternative fuels. Moreover, government regulations, such as regulation of natural gas transportation and price
controls, can affect product prices in the long term. Lower oil and gas prices may reduce the amount of oil and gas that is economic to produce and will reduce net profits available to the trust. The
volatility of energy prices reduces the predictability of future cash distributions to trust unitholders.

Increased Production and Development Costs.Production and development costs are deducted in the calculation of the trust's
share of net proceeds. Accordingly, higher or lower production and development costs, without concurrent increases in revenue, will directly decrease or increase the amount received by the trust for
its net profits interests. If development and production costs in a particular state exceed the production proceeds from the properties, the trust will not receive net proceeds for those properties
until future proceeds from production in that state exceed the total of the
excess costs plus accrued interest during the deficit period. Development activities may not generate sufficient additional revenue to repay the costs.

Reserve Estimates.Estimating reserves is inherently uncertain. Petroleum engineers consider many factors and make
assumptions in estimating reserves and future net cash flows. Lower oil and gas prices generally cause lower estimates of proved reserves. Ultimately, actual production, revenues and expenditures for
the underlying properties will vary from estimates and those variations could be material. The trust's reserve quantities are based on estimates of reserves for the underlying properties. The method
of allocating a portion of those reserves to the trust is complicated because the trust holds an interest in net profits and does not own a specific percentage of the oil and gas reserves.

Operating Risks.The occurrence of drilling, production or transportation accidents at any of the underlying properties will
reduce trust distributions by the amount of uninsured costs. These accidents may result in personal injuries, property damage, damage to productive formations or equipment and environmental damages.
Any uninsured costs would be deducted as production costs in calculating net proceeds payable to the trust.

Trust's Assets are Depleting Assets.The net proceeds payable to the trust are derived from the sale of depleting assets.
Accordingly, the portion of the distributions to trust unitholders attributable to depletion may be considered a return of capital. The reduction in proved reserve quantities is a common measure of
the depletion. Future maintenance and development projects on the underlying properties will affect the quantity of proved reserves. The timing and size of these projects will depend on the market
prices of oil and gas. If operators of the properties do not implement additional maintenance and development projects, the future rate of production decline of proved reserves may be higher than the
rate currently expected by XTO Energy.

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Item 7a.Quantitative and Qualitative Disclosures about Market Risk

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

Item 8.Financial Statements and Supplementary Data

The financial statements of the trust and the notes thereto, together with the related reports of KPMG LLP dated March 14, 2003 and Arthur Andersen LLP
dated March 19, 2002, appearing on pages 8 through 12 of the trust's Annual Report to unitholders for the year ended December 31, 2002 are incorporated herein by reference.

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

On June 25, 2002, the trustee appointed KPMG LLP as independent auditors for fiscal year 2002 to replace Arthur Andersen LLP, effective with such
appointment. Information regarding this change in independent auditors is included in the trust's current report on Form 8-K dated June 25, 2002.

There
have been no other changes in accountants and there have been no disagreements with accountants on any matter of accounting principles or practices or financial statement
disclosures during the two years ended December 31, 2002.

15

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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.

Section 16(a)
of the Securities Exchange Act of 1934 requires that beneficial owners of more than 10% of the registrant's equity securities file initial reports of beneficial
ownership and reports of changes in beneficial ownership with the Securities and Exchange Commission and the New York Stock Exchange. Copies of the reports must be provided to the trust. To the
trustee's knowledge, based solely on the information furnished to the trust, the trust is unaware of any person that failed to file on a timely basis reports required by Section 16(a) filing
requirements with respect to the trust units of beneficial interest during and for the year ended December 31, 2002. The trust has determined that Mr. Bob R. Simpson, Chairman and
Chief Executive Officer of XTO Energy Inc., had four late filings with respect to one transaction in trust units during 1999. The transaction occurred prior to the date the Securities and
Exchange Commission took the position that officers and directors of XTO Energy may be subject to the filing requirements of Section 16(a) with respect to transactions in trust units. The
transaction has now been reported.

Item 11.Executive Compensation

The trustee received the following annual compensation from 2000 through 2002 as specified in the trust indenture:

Name and Principal Position

Year

Other Annual
Compensation (1)Bank of America, N.A., Trustee

2002

$
35,0002001


35,0002000


35,000


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Item 12.Security Ownership of Certain Beneficial Owners and Management

The trust has no equity compensation plans.

(a)Security Ownership of Certain Beneficial Owners.The following table sets forth as of March 3, 2003 information
with respect to each person known to the trustee to beneficially own more than 5% of the outstanding units of the trust:

Name and Address

Amount and Nature of
Beneficial Ownership

Percent
of ClassXTO Energy Inc.

21,705,893 units (1)

54.3%810 Houston Street, Suite 2000
Fort Worth, Texas 76102


---

(b)Security Ownership of Management.The trust has no directors or executive officers. As of February 28, 2003, Bank
of America, N.A. owned, in various fiduciary capacities, 98,300 units with a shared right to vote 35,300 of these units and no right to vote 63,000 of these units. Bank of America, N.A.

16

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disclaims any beneficial interests in these units. The number of units reflected in this paragraph includes units held by all branches of Bank of America, N.A.

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

Item 13.Certain Relationships and Related Transactions

In computing net profits income paid to the trust for the net profits interests, XTO Energy deducts an overhead charge for reimbursement of administrative
expenses of operating the underlying properties. This charge at December 31, 2002 was approximately $720,000 per month, or $8,640,000 annually (net to the trust of $576,000 per month or
$6,912,000 annually), and is subject to annual adjustment based on an oil and gas industry index as defined in the trust agreement.

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

Item 14.Controls and Procedures

Within the 90 days prior to the date of this report, the trustee carried out an evaluation of the effectiveness of the design and operation of the trust's
disclosure controls and procedures pursuant to Exchange Act Rule 13a-14. Based upon that evaluation, the trustee concluded that the trust's disclosure controls and procedures are
effective in timely alerting the trustee to material information relating to the trust required to be included in the trust's periodic filings with the Securities and Exchange Commission. In its
evaluation of disclosure controls and procedures, the trustee has relied, to the extent considered reasonable, on information provided by XTO Energy. No significant changes in the trust's internal
controls or other factors that could affect these controls have occurred subsequent to the date of such evaluation.

PART IV

Item 15.Exhibits, Financial Statement Schedules and Reports on Form 8-K



17

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(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 (predecessor of XTO Energy Inc.) 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 (predecessor of XTO Energy Inc.) to NationsBank, N.A. (now Bank of America, N.A.), as trustee, dated
December 1, 1998, heretofore filed as Exhibit 10.1.1 to the trust's RegistrationStatement 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 (predecessor of XTO Energy Inc.) to NationsBank, N.A. (now Bank of America, N.A.), as trustee, dated
December 1, 1998, heretofore filed as Exhibit 10.1.2 to the trust's Registration Statement No. 333-68441 on Form S-1 filed with the Securities and Exchange Commission on March 16, 1999, is incorporated herein by
reference.(d)
Net Overriding Royalty Conveyance (Hugoton Royalty Trust, 80%Wyoming) as amended and restated from Cross Timbers Oil Company (predecessor of XTO Energy Inc.) to NationsBank, N.A. (now Bank of America, N.A.), as trustee, dated
December 1, 1998, heretofore filed as Exhibit 10.1.3 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, 2002(23.1)

Consent of KPMG LLP(23.2)

Notice Regarding Consent of Arthur Andersen LLP(23.3)

Consent of Miller and Lents, Ltd.(99.1)

Trustee certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002


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.

During
the last quarter of the trust's fiscal year ended December 31, 2002, there were no reports filed on Form 8-K by the trust with the Securities and
Exchange Commission.

18

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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
|-------------------- |  | -------------------------------------------------------
|                     |  | By:                                                    
|                     |  | XTO ENERGY INC.                                        
|Date: March 31, 2003 |  | By:                                                    

(The trust has no directors or executive officers.)

19

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CERTIFICATIONS

I,
Nancy G. Willis, certify that:

In
giving the certifications in paragraphs 4, 5 and 6 above, I have relied to the extent I consider reasonable on information provided to me by XTO Energy Inc.

|Date: March 31, 2003 |  | By |                                                                                 
|-------------------- |  | -- | --------------------------------------------------------------------------------
|                     |  |    | /s/NANCY G. WILLISNancy G. Willis
Assistant Vice President
Bank of America, N.A.

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