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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, 2003 |  | Commission file number 1-10982



Cross Timbers
Royalty Trust

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



|                                                               |  |                                     
|-------------------------------------------------------------- |  | ------------------------------------
|Texas                                                          |  | 75-6415930                          
|(State or other jurisdiction of incorporation or organization) |  | (I.R.S. Employer Identification No.)



|                                                            |  |           
|----------------------------------------------------------- |  | ----------
|Bank of America, N.A. Trustee P.O. Box 830650 Dallas, Texas |  | 75283-0650
|(Address of principal executive offices)                    |  | (Zip Code)



Registrants
telephone number including area code: (877) 228-5084



Securities registered pursuant to Section 12(b) of the Act:



|                             |  |                                          
|---------------------------- |  | -----------------------------------------
|Title of each class          |  | Name of each exchange on which registered
|Units of Beneficial Interest |  | New York Stock Exchange                  



Securities
registered pursuant to Section 12(g) of the Act: None



Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was
required to file such reports) and (2) has been subject to such filing requirements for the past 90 days. Yes  x     No ̈



Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrants knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. x



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 30, 2003 (the last business day of its most recently completed second fiscal quarter), held by non-affiliates of the registrant on that date was approximately $110 million.



At March 5, 2004, there were 6,000,000 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:



2003 Annual Report to UnitholdersPart II



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PART I



Item 1.Business



Cross Timbers Royalty Trust is an express trust created under the laws of Texas pursuant to the Cross Timbers Royalty Trust
Indenture entered into on February 12, 1991 between predecessors of XTO Energy Inc., as grantors, and NCNB Texas National Bank, as trustee. Bank of America, 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 877-228-5084).



The trusts internet web site is www.crosstimberstrust.com. 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.



On
February 12, 1991, the predecessors of XTO Energy (formerly known as Cross Timbers Oil Company) conveyed defined net profits interests to the trust under five separate conveyances:



| |  |  | one in each of the states of Texas, Oklahoma and New Mexico, to convey a 90% defined net profits interest carved out of substantially all royalty and overriding royalty interests
owned by the predecessors in those states, and
| | - |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | one in each of the states of Texas and Oklahoma, to convey a 75% defined net profits interest carved out of specific working interests owned by the predecessors in those states.
| | - |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



The conveyance of these net profits interests
was effective for production from October 1, 1990. The net profits interests and the underlying properties are further described under Item 2.



In exchange for the conveyance of the net profits interests to the trust, the predecessors of XTO Energy received 6,000,000 units of beneficial interest
of the trust. Predecessors of XTO Energy distributed units to their owners in February 1991 and November 1992, and in February 1992, sold units in the trusts initial public offering. Units are listed and traded on the New York Stock Exchange
under the symbol CRT. During 1996 and 1997, XTO Energy purchased 1,360,000 units on the open market. On September 18, 2003, XTO Energy distributed all of the 1,360,000 trust units it owned as a dividend to its common stockholders. As of
this date, XTO Energy is not a unitholder of the trust.



Under
the terms of each of the five conveyances, the trust receives net profits income from the net profits interests on the last business day of each month. Net profits income is determined by XTO Energy by multiplying the net profit percentage (90% or
75%) times net proceeds from the underlying properties for each conveyance during the previous month. Net proceeds are the gross proceeds received from the sale of production, less production costs. For the 90% net profits interests and the 75% net
profits interests, production costs generally include applicable property taxes, transportation, marketing and other charges. For the 75% net profits interests only, production costs also include capital and operating costs paid (e.g.,
drilling, production and other direct costs of owning and operating the property) and a monthly overhead charge that is adjusted annually. The monthly overhead charge at December 31, 2003 was $22,742 ($17,057 net to the trust). If production costs
exceed gross proceeds for any conveyance, this excess is carried forward to future monthly computations of net proceeds until the excess costs (plus interest accrued as specified in the conveyances) are completely recovered. Excess production costs
and related accrued interest from one conveyance cannot be used to reduce net proceeds from any other conveyance.



The trust is not liable for any production costs or liabilities attributable to the net profits interests. If at any time the trust receives net profits
income in excess of the amount due, the trust is not obligated to return the 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.



1



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Approximately 20 of the underlying royalty interests in the San Juan Basin burden working interests in
properties operated by XTO Energy. Otherwise, XTO Energy does not operate or control any working interests associated with the underlying royalty interests, nor does it operate or control any of the underlying working interest properties.



As a working interest owner, XTO Energy can generally decline
participation in any operation and allow consenting parties to conduct such operations, as provided under the operating agreements. XTO Energy also can assign, sell, or otherwise transfer its interest in the underlying properties, subject to the net
profits interests, or can abandon an underlying property that is a working interest if it is incapable of producing in paying quantities, as determined by XTO Energy.



To the extent allowed, 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.



Net profits income received by the trust on or before the last business day of the month is generally attributable to oil production two months prior and
gas production three months prior. The monthly distribution amount to unitholders is determined by:



Adding



| | (1) |  | net profits income received,
| | --- |  | ----------------------------

| | (2) |  | estimated interest income to be received on the monthly distribution amount, including an adjustment for the difference between the estimated and actual interest received for the
prior monthly distribution amount,
| | --- |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| | (3) |  | cash available as a result of reduction of cash reserves, and
| | --- |  | -------------------------------------------------------------

| | (4) |  | other cash receipts, and
| | --- |  | ------------------------



Subtracting



| | (1) |  | liabilities paid and
| | --- |  | --------------------

| | (2) |  | the reduction in cash available due to establishment of or increase in any cash reserve.
| | --- |  | ----------------------------------------------------------------------------------------



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



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



The trustees function is to collect the 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 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 73% of the net profits income received by the trust during 2003, as well as 76% of the estimated proved reserves of the net profits
interests at December 31, 2003 (based on estimated future net cash flows using year-end oil and gas prices), is attributable to natural gas. There is generally a greater demand for gas during the winter. Otherwise, trust income is not subject to
seasonal factors, nor dependent upon patents, licenses, franchises or concessions. The trust conducts no research activities.



2



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Item 2.Properties



The net profits interests are the principal asset of the trust. The trustee
cannot acquire any other asset, with the exception of certain short-term investments as specified under Item 1. The trustee is prohibited from selling any portion of the net profits interests unless approved by at least 80% of the unitholders or at
such time as trust gross revenue is less than $1,000,000 for two successive years.



The net profits interests comprise:



| |  |  | the 90% net profits interests which are carved from:
| | - |  | ----------------------------------------------------



| | a) |  | producing royalty and overriding royalty interest properties in Texas, Oklahoma and New Mexico, and
| | -- |  | ---------------------------------------------------------------------------------------------------



| | b) |  | 11.11% nonparticipating royalty interests in nonproducing properties located primarily in Texas and Oklahoma;
| | -- |  | -------------------------------------------------------------------------------------------------------------



| |  |  | the 75% net profits interests which are carved from nonoperated working interests in four properties in Texas and three properties in Oklahoma.
| | - |  | -----------------------------------------------------------------------------------------------------------------------------------------------



All underlying royalties, underlying nonproducing royalties and underlying
working interest properties are currently owned by XTO Energy. XTO Energy may sell all or any portion of the underlying properties at any time, subject to and burdened by the net profits interests.



Producing Acreage, Wells and Drilling



Underlying Royalties.    The underlying royalties
are royalty and overriding royalty interests primarily located in mature producing oil and gas fields. The most significant producing region in which the underlying royalties are located is the San Juan Basin in northwestern New Mexico. The
trusts estimated proved gas reserves from this region totaled 25.0 Bcf at December 31, 2003, or approximately 81% of trust total gas reserves at that date. XTO Energy estimates that underlying royalties in the San Juan Basin include more than
2,000 gross (approximately 30 net) wells, covering over 60,000 gross acres. Most of these wells are operated by BP America Production Company or Burlington Resources Oil & Gas Company. Production from conventional gas wells is primarily from the
Dakota, Mesaverde and Pictured Cliffs formations.



Approximately 24% of trust 2003 gas sales volumes were from coal seam production in the San Juan Basin. Through the year 2002, sales of certain coal seam gas qualified for a federal income tax credit. See RegulationCoal Seam Tax
Credit. In October 2002, regulatory authorities approved increasing the density of coal seam wells drilled in the San Juan Basin from 320 acres to 160 acres, doubling the number of drill wells allowed. Increasing the density of coal seam wells
could impact a significant portion of the trusts acreage. The development of the additional wells is expected to occur over the next few years. XTO Energy has informed the trustee that it believes operators will pursue increased density
drilling, but the effect on the trust is unknown.



Most of the
trusts San Juan Basin conventional, or non-coal seam, production is from the Mesaverde formation. This formation has been approved for increased density drilling, doubling the number of drill wells allowed to four per spacing unit. XTO Energy
has advised the trustee that the trust received net proceeds from additional Mesaverde wells in 2002 and 2003, and that it believes operators will further develop the Mesaverde formation underlying the net profits interests.



In the past, additional eastward pipeline capacity was completed in the San
Juan Basin, reducing the dependence of San Juan Basin gas on California markets and effectively increasing San Juan Basin gas prices in relation to prices from other regions. Gas-powered electricity generation continues to increase in the southwest
U.S., and future pipelines are being discussed to serve the growing demand.



3



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The underlying royalties also include royalties in the Sand Hills field of Crane County, Texas. Most of
these properties are operated by ExxonMobil Corporation or ChevronTexaco. The Sand Hills field was discovered in 1931 and includes production from three main intervals, the Tubb, McKnight and Judkins. Development potential for the field includes
recompletions and additional infill drilling.



The underlying
royalties contain approximately 462,000 gross (approximately 26,000 net) producing acres. Well counts for the underlying royalties cannot be provided because information regarding the number of wells on royalty properties is generally not made
available to royalty interest owners.



Underlying Working
Interest Properties.    The underlying working interest properties, detailed below, are developed properties undergoing secondary or tertiary recovery operations:



|                        |  |                 |                 |                              |  |                         |   |  |     |  
|----------------------- |  | --------------- | --------------- | ---------------------------- |  | ----------------------- | - |  | --- | -
|Unit                    |  | County/State    |                 | Operator                     |  | Ownership of XTO Energy |  
|                        |  |                 | WorkingInterest |                              |  | RevenueInterest         |  
|North Cowden            |  | Ector/Texas     |                 | Occidental Permian, Ltd.     |  | 1.7                     | % |  | 1.4 | %
|North Central Levelland |  | Hockley/Texas   |                 | ExxonMobil Corporation       |  | 3.2                     | % |  | 2.1 | %
|Penwell                 |  | Ector/Texas     |                 | ChevronTexaco                |  | 5.2                     | % |  | 4.6 | %
|Sharon Ridge Canyon     |  | Borden/Texas    |                 | ExxonMobil Corporation       |  | 4.3                     | % |  | 2.8 | %
|Hewitt                  |  | Carter/Oklahoma |                 | ExxonMobil Corporation       |  | 11.3                    | % |  | 9.9 | %
|Wildcat Jim Penn        |  | Carter/Oklahoma |                 | Patina Oil & Gas Corporation |  | 8.6                     | % |  | 7.5 | %
|South Graham Deese      |  | Carter/Oklahoma |                 | Lamamco Drilling Company     |  | 8.2                     | % |  | 7.0 | %



The underlying working
interest properties consist of 60,154 gross (2,290 net) producing acres. As of December 31, 2003, there were 1,474 gross (66.1 net) productive oil wells, 1,039 gross (44.1 net) injection wells and no wells in process of drilling on these properties.
During 2003, 11 gross (0.2 net) wells were drilled, during 2002, nine gross (0.2 net) wells were drilled and during 2001, 50 gross (1.4 net) wells were drilled. Six gross (0.1 net) wells drilled in 2003, four gross (0.1 net) wells drilled in
2002 and nine gross (0.2 net) wells drilled in 2001 were water injection wells.



4



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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 oil production and three months after gas production. Oil and gas production and average sales prices attributable to the underlying properties and the net profits interests for the three years ended December 31, 2003 were
as follows:



|                       |  |                           |  |                           |  |           |  |         |  |         |  |         |  |           |  |           |  |          
|---------------------- |  | ------------------------- |  | ------------------------- |  | --------- |  | ------- |  | ------- |  | ------- |  | --------- |  | --------- |  | ---------
|                       |  | 90% Net Profits Interests |  | 75% Net Profits Interests |  | Total    
|                       |  | 2003                      |  | 2002                      |  | 2001      |  | 2003    |  | 2002    |  | 2001    |  | 2003      |  | 2002      |  | 2001     
|Production             |  |                           |  |                           |  |           |  |         |  |         |  |         |  |           |  |           |  |          
|                       |  |                           |  |                           |  |           |  |         | 
|Underlying Properties  |  |                           |  |                           |  |           |  |         |  |         |  |         |  |           |  |           |  |          
|                       |  |                           |  |                           |  |           |  |         | 
|OilSales (Bbls)       |  | 70,742                    |  | 95,789                    |  | 92,329    |  | 228,127 |  | 243,186 |  | 258,362 |  | 298,869   |  | 338,975   |  | 350,691  
|Average per day (Bbls) |  | 194                       |  | 263                       |  | 253       |  | 625     |  | 666     |  | 708     |  | 819       |  | 929       |  | 961      
|GasSales (Mcf)        |  | 2,604,146                 |  | 2,947,897                 |  | 2,845,132 |  | 73,314  |  | 82,052  |  | 87,071  |  | 2,677,460 |  | 3,029,949 |  | 2,932,203
|Average per day (Mcf)  |  | 7,135                     |  | 8,076                     |  | 7,795     |  | 201     |  | 225     |  | 238     |  | 7,336     |  | 8,301     |  | 8,033    
|                       |  |                           |  |                           |  |           |  |         | 
|Net Profits Interests  |  |                           |  |                           |  |           |  |         |  |         |  |         |  |           |  |           |  |          
|                       |  |                           |  |                           |  |           |  |         | 
|OilSales (Bbls)       |  | 59,781                    |  | 85,017                    |  | 82,745    |  | 70,736  |  | 53,232  |  | 62,933  |  | 130,517   |  | 138,249   |  | 145,678  
|Average per day (Bbls) |  | 164                       |  | 233                       |  | 227       |  | 194     |  | 146     |  | 172     |  | 358       |  | 379       |  | 399      
|GasSales (Mcf)        |  | 2,315,504                 |  | 2,630,283                 |  | 2,530,916 |  | 22,026  |  | 18,511  |  | 21,291  |  | 2,337,530 |  | 2,648,794 |  | 2,552,207
|Average per day (Mcf)  |  | 6,344                     |  | 7,206                     |  | 6,934     |  | 60      |  | 51      |  | 58      |  | 6,404     |  | 7,257     |  | 6,992    
|                       |  |                           |  |                           |  |           |  |         | 
|Average Sales Price    |  |                           |  |                           |  |           |  |         |  |         |  |         |  |           |  |           |  |          
|Oil (per Bbl)          |  | $28.95                    |  | $22.87                    |  | $24.22    |  | $27.76  |  | $22.10  |  | $25.26  |  | $28.04    |  | $22.31    |  | $24.99   
|Gas (per Mcf)          |  | $  4.89                   |  | $  2.80                   |  | $  5.14   |  | $  4.07 |  | $  2.48 |  | $  3.31 |  | $  4.86   |  | $  2.79   |  | $  5.09  



Nonproducing Acreage



The underlying nonproducing royalties contain
approximately 200,000 gross (approximately 3,000 net) acres in Texas, Oklahoma and New Mexico which were nonproducing at the date of the trusts creation. XTO Energy is the owner of underlying mineral interests in the majority of this acreage.
The trust is entitled to 10% of oil and gas production attributable to the underlying mineral properties, but is not entitled to delay rental payments or lease bonuses. There has been no significant development of such nonproducing acreage since the
trusts creation. Included in the December 2002 distribution to unitholders was $477,000, or approximately $0.08 per unit, related to a one-time correction of the trusts interest in these properties.



Pricing and Sales Information



Oil and gas are generally sold from the underlying properties at
market-sensitive prices. The majority of sales from the underlying working interest properties are to major oil and gas companies. Information about purchasers of oil and gas from royalty properties is generally not provided by operators to XTO
Energy as a royalty owner, or to the trust.



Oil and Natural Gas Reserves



General



Miller and Lents, Ltd., independent petroleum engineers, has estimated oil
and gas reserves attributable to the underlying properties as of December 31, 2003, 2002, 2001 and 2000. 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.



5



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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 75% net profits interests in the working interest properties have effectively been reduced to reflect recovery of the trusts 75% portion of applicable production and development
costs. Because trust reserve quantities are determined using an allocation formula, any fluctuations in actual or assumed prices or costs will result in revisions to the estimated reserve quantities allocated to the net profits interests.



The standardized measure of discounted future net cash flows
and changes in such discounted cash flows as presented below are prepared using assumptions required by the Financial Accounting Standards Board. Such assumptions include the use of year-end prices for oil and gas and year-end costs for estimated
future 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.



Estimated costs to plug and abandon wells on the
underlying working interest properties at the end of their productive lives have not been deducted from cash flows since this is not a legal obligation of the trust. Such costs will only be deducted from net proceeds payable to the trust if net
proceeds from the related conveyance exceed such costs when paid.



Year-end oil prices used to determine the standardized measure were based on a West Texas Intermediate crude oil posted price of $29.25 per Bbl in 2003, $28.00 per Bbl in 2002, $16.75 per Bbl in 2001 and $23.75 per Bbl in 2000. The year-end
weighted average realized gas prices used to determine the standardized measure were $5.15 per Mcf in 2003, $4.06 per Mcf in 2002, $2.28 per Mcf in 2001 and $9.48 per Mcf in 2000.



Proved Reserves



|                                            |  |                          |   |  |                          |   |  |           |   |  |          |   |  |           |   |  |           |   |  |           |   |  |           |  
|------------------------------------------- |  | ------------------------ | - |  | ------------------------ | - |  | --------- | - |  | -------- | - |  | --------- | - |  | --------- | - |  | --------- | - |  | --------- | -
|                                            |  | Net Profits Interests    |   |  | UnderlyingProperties     |  
|(in thousands)                              |  | 90% Net ProfitsInterests |   |  | 75% Net ProfitsInterests |   |  | Total     |   | 
|                                            |  | Oil(Bbls)                |   |  | Gas (Mcf)                |   |  | Oil(Bbls) |   |  | Gas(Mcf) |   |  | Oil(Bbls) |   |  | Gas (Mcf) |   |  | Oil(Bbls) |   |  | Gas (Mcf) |  
|Balance, December 31, 2000                  |  | 678.0                    |   |  | 34,207.2                 |   |  | 1,426.0   |   |  | 572.4    |   |  | 2,104.0   |   |  | 34,779.6  |   |  | 4,243.0   |   |  | 39,377.0  |  
|Extensions, discoveries and other additions |  | 12.3                     |   |  | 247.8                    |   |  | -0-       |   |  | -0-      |   |  | 12.3      |   |  | 247.8     |   |  | 13.7      |   |  | 274.8     |  
|Revisions of prior estimates                |  | 6.9                      |   |  | (486.5                   | ) |  | (678.2    | ) |  | (282.9   | ) |  | (671.3    | ) |  | (769.4    | ) |  | (483.6    | ) |  | (713.2    | )
|Production                                  |  | (82.8                    | ) |  | (2,530.9                 | ) |  | (62.9     | ) |  | (21.3    | ) |  | (145.7    | ) |  | (2,552.2  | ) |  | (350.7    | ) |  | (2,932.2  | )
|                                            |  |                          |   |  |                          |   |  |           |   |  |          |   |  |           |   |  |           |   |  |           |   |  |           |  
|Balance, December 31, 2001                  |  | 614.4                    |   |  | 31,437.6                 |   |  | 684.9     |   |  | 268.2    |   |  | 1,299.3   |   |  | 31,705.8  |   |  | 3,422.4   |   |  | 36,006.4  |  
|Extensions, discoveries and other additions |  | 11.5                     |   |  | 48.3                     |   |  | -0-       |   |  | -0-      |   |  | 11.5      |   |  | 48.3      |   |  | 12.8      |   |  | 53.7      |  
|Revisions of prior estimates                |  | 104.0                    |   |  | 1,755.3                  |   |  | 439.3     |   |  | 231.0    |   |  | 543.3     |   |  | 1,986.3   |   |  | 560.7     |   |  | 2,266.6   |  
|Production                                  |  | (85.0                    | ) |  | (2,630.3                 | ) |  | (53.2     | ) |  | (18.5    | ) |  | (138.2    | ) |  | (2,648.8  | ) |  | (339.0    | ) |  | (3,029.9  | )
|                                            |  |                          |   |  |                          |   |  |           |   |  |          |   |  |           |   |  |           |   |  |           |   |  |           |  
|Balance, December 31, 2002                  |  | 644.9                    |   |  | 30,610.9                 |   |  | 1,071.0   |   |  | 480.7    |   |  | 1,715.9   |   |  | 31,091.6  |   |  | 3,656.9   |   |  | 35,296.8  |  
|Extensions, discoveries and other additions |  | 2.5                      |   |  | 277.6                    |   |  | -0-       |   |  | -0-      |   |  | 2.5       |   |  | 277.6     |   |  | 2.8       |   |  | 308.6     |  
|Revisions of prior estimates                |  | 33.1                     |   |  | 2,068.2                  |   |  | (8.9      | ) |  | (28.5    | ) |  | 24.2      |   |  | 2,039.7   |   |  | 135.1     |   |  | 2,366.1   |  
|Production                                  |  | (59.8                    | ) |  | (2,315.5                 | ) |  | (70.7     | ) |  | (22.0    | ) |  | (130.5    | ) |  | (2,337.5  | ) |  | (298.9    | ) |  | (2,677.5  | )
|                                            |  |                          |   |  |                          |   |  |           |   |  |          |   |  |           |   |  |           |   |  |           |   |  |           |  
|Balance, December 31, 2003                  |  | 620.7                    |   |  | 30,641.2                 |   |  | 991.4     |   |  | 430.2    |   |  | 1,612.1   |   |  | 31,071.4  |   |  | 3,495.9   |   |  | 35,294.0  |  
|                                            |  |                          |   |  |                          |   |  |           |   |  |          |   |  |           |   |  |           |   |  |           |   |  |           |  



6



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Revisions of prior estimates of the 75% net profits interests proved oil reserves and the underlying
properties proved oil reserves in 2001 and 2002 were primarily the result of changes in the year-end oil price used in estimating proved reserves. During 2002 and 2003, upward revisions of the 90% net profits interests proved gas reserves were
primarily because of lower than anticipated production declines and higher year-end gas prices. Downward revisions of the 90% net profits interests proved reserves in 2001 were primarily because of significantly lower year-end prices. Higher
downward revisions for the net profits interests as compared to underlying properties in 2001 was caused by significant declines in the year-end oil and gas prices which resulted in decreased reserves allocated to the trust. See General
above.



Proved Developed Reserves



|                  |  |                          |  |                          |  |           |  |          |  |           |  |           |  |            |  |          
|----------------- |  | ------------------------ |  | ------------------------ |  | --------- |  | -------- |  | --------- |  | --------- |  | ---------- |  | ---------
|                  |  | Net Profits Interests    |  | Underlying Properties   
|(in thousands)    |  | 90% Net ProfitsInterests |  | 75% Net ProfitsInterests |  | Total     | 
|                  |  | Oil(Bbls)                |  | Gas (Mcf)                |  | Oil(Bbls) |  | Gas(Mcf) |  | Oil(Bbls) |  | Gas (Mcf) |  | Oil (Bbls) |  | Gas (Mcf)
|December 31, 2000 |  | 675.0                    |  | 32,371.1                 |  | 1,317.8   |  | 553.5    |  | 1,992.8   |  | 32,924.6  |  | 4,028.8    |  | 37,300.0 
|                  |  |                          |  |                          |  |           |  |          |  |           |  |           |  |            |  |          
|December 31, 2001 |  | 611.4                    |  | 29,608.5                 |  | 602.0     |  | 253.7    |  | 1,213.4   |  | 29,862.2  |  | 3,208.3    |  | 33,937.3 
|                  |  |                          |  |                          |  |           |  |          |  |           |  |           |  |            |  |          
|December 31, 2002 |  | 642.4                    |  | 29,330.7                 |  | 1,071.0   |  | 480.7    |  | 1,713.4   |  | 29,811.4  |  | 3,654.1    |  | 33,874.4 
|                  |  |                          |  |                          |  |           |  |          |  |           |  |           |  |            |  |          
|December 31, 2003 |  | 619.3                    |  | 29,802.8                 |  | 991.4     |  | 430.2    |  | 1,610.7   |  | 30,233.0  |  | 3,494.3    |  | 34,362.5 
|                  |  |                          |  |                          |  |           |  |          |  |           |  |           |  |            |  |          



Standardized Measure of Discounted
Future Net Cash Flows from Proved Reserves



|                        |  |                           |         |          |                           |   |         |             |   |   |         |         |   |      |         |   |      |   |         |      |  |   |        |   |  |      |         |   |  |   |         |   |  |   |         |  
|----------------------- |  | ------------------------- | ------- | -------- | ------------------------- | - | ------- | ----------- | - | - | ------- | ------- | - | ---- | ------- | - | ---- | - | ------- | ---- |  | - | ------ | - |  | ---- | ------- | - |  | - | ------- | - |  | - | ------- | -
|(in thousands)          |  | 90% Net Profits Interests |         |          | 75% Net Profits Interests |   |         | Total       |  
|                        |  | December 31               |         |          | December 31               |   |         | December 31 |  
|                        |  | 2003                      |         |          | 2002                      |   |         | 2001        |   |   | 2003    |         |   | 2002 |         |   | 2001 |   |         | 2003 |  |   | 2002   |   |  | 2001 |        
|Net Profits Interests   |  |                           |         |          |                           |   |         |             |   |   |         |         |   |      |         |   |      |   |         |      |  |   |        |   |  |      |         |   |  |   |         |   |  |   |         |  
|                        |  |                           |         |          |                           |   |         |             |  
|Future cash inflows     |  | $                         | 178,591 |          |                           | $ | 145,445 |             |   | $ | 87,042  |         |   | $    | 31,527  |   |      | $ | 32,474  |      |  | $ | 12,275 |   |  | $    | 210,118 |   |  | $ | 177,919 |   |  | $ | 99,317  |  
|Future production taxes |  |                           | (14,267 | )        |                           |   | (11,596 | )           |   |   | (6,945  | )       |   |      | (2,156  | ) |      |   | (2,212  | )    |  |   | (831   | ) |  |      | (16,423 | ) |  |   | (13,808 | ) |  |   | (7,776  | )
|                        |  |                           |         |          |                           |   |         |             |   |   |         |         |   |      |         |   |      |   |         |      |  |   |        |   |  |      |         |   |  |   |         |   |  |   |         |  
|Future net cash flows   |  |                           | 164,324 |          |                           |   | 133,849 |             |   |   | 80,097  |         |   |      | 29,371  |   |      |   | 30,262  |      |  |   | 11,444 |   |  |      | 193,695 |   |  |   | 164,111 |   |  |   | 91,541  |  
|10% discount factor     |  |                           | (86,131 | )        |                           |   | (69,912 | )           |   |   | (42,004 | )       |   |      | (13,709 | ) |      |   | (14,208 | )    |  |   | (5,493 | ) |  |      | (99,840 | ) |  |   | (84,120 | ) |  |   | (47,497 | )
|                        |  |                           |         |          |                           |   |         |             |   |   |         |         |   |      |         |   |      |   |         |      |  |   |        |   |  |      |         |   |  |   |         |   |  |   |         |  
|Standardized measure    |  | $                         | 78,193  |          |                           | $ | 63,937  |             |   | $ | 38,093  |         |   | $    | 15,662  |   |      | $ | 16,054  |      |  | $ | 5,951  |   |  | $    | 93,855  |   |  | $ | 79,991  |   |  | $ | 44,044  |  
|                        |  |                           |         |          |                           |   |         |             |   |   |         |         |   |      |         |   |      |   |         |      |  |   |        |   |  |      |         |   |  |   |         |   |  |   |         |  
|                        |  |                           |         |          |                           |   |         |             |  
|Underlying Properties   |  |                           |         |          |                           |   |         |             |   |   |         |         |   |      |         |   |      |   |         |      |  |   |        |   |  |      |         |   |  |   |         |   |  |   |         |  
|                        |  |                           |        
|Future cash inflows     |  |                           | $       | 287,484  |                           |   | $       | 250,219     |   |   | $       | 145,759 |  
|Future costs:           |  |                           |         |          |                           |   |         |             |   |   |         |         |  
|Production              |  |                           |         | (65,741  | )                         |   |         | (61,148     | ) |   |         | (40,984 | )
|Development             |  |                           |         | -0-      |                           |   |         | -0-         |   |   |         | (520    | )
|                        |  |                           |         |          |                           |   |         |             |   |   |         |         |   |      |         |   |      |   |         |      |  |   |        |   |  |      |         |   |  |   |         |   |  |   |         |  
|Future net cash flows   |  |                           |         | 221,743  |                           |   |         | 189,071     |   |   |         | 104,255 |  
|10% discount factor     |  |                           |         | (113,979 | )                         |   |         | (96,624     | ) |   |         | (53,994 | )
|                        |  |                           |         |          |                           |   |         |             |   |   |         |         |   |      |         |   |      |   |         |      |  |   |        |   |  |      |         |   |  |   |         |   |  |   |         |  
|Standardized measure    |  |                           | $       | 107,764  |                           |   | $       | 92,447      |   |   | $       | 50,261  |  
|                        |  |                           |         |          |                           |   |         |             |   |   |         |         |   |      |         |   |      |   |         |      |  |   |        |   |  |      |         |   |  |   |         |   |  |   |         |  



7



---

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



|                                                         |  |                           |         |         |                           |   |        |         |   |   |          |          |   |      |        |   |      |   |        |      |  |   |         |   |  |      |         |   |  |   |        |   |  |   |          |  
|-------------------------------------------------------- |  | ------------------------- | ------- | ------- | ------------------------- | - | ------ | ------- | - | - | -------- | -------- | - | ---- | ------ | - | ---- | - | ------ | ---- |  | - | ------- | - |  | ---- | ------- | - |  | - | ------ | - |  | - | -------- | -
|(in thousands)                                           |  | 90% Net Profits Interests |         |         | 75% Net Profits Interests |   |        | Total   |  
|                                                         |  | 2003                      |         |         | 2002                      |   |        | 2001    |   |   | 2003     |          |   | 2002 |        |   | 2001 |   |        | 2003 |  |   | 2002    |   |  | 2001 |        
|                                                         |  |                           |         |         |                           |   |        |         |  
|Net Profits Interests                                    |  |                           |         |         |                           |   |        |         |   |   |          |          |   |      |        |   |      |   |        |      |  |   |         |   |  |      |         |   |  |   |        |   |  |   |          |  
|                                                         |  |                           |         |         |                           |   |        |         |  
|Standardized measure, January 1                          |  | $                         | 63,937  |         |                           | $ | 38,093 |         |   | $ | 150,759  |          |   | $    | 16,054 |   |      | $ | 5,951  |      |  | $ | 18,668  |   |  | $    | 79,991  |   |  | $ | 44,044 |   |  | $ | 169,427  |  
|Extensions, discoveries and other additions              |  |                           | 859     |         |                           |   | 327    |         |   |   | 507      |          |   |      | -0-    |   |      |   | -0-    |      |  |   | -0-     |   |  |      | 859     |   |  |   | 327    |   |  |   | 507      |  
|Accretion of discount                                    |  |                           | 5,367   |         |                           |   | 3,238  |         |   |   | 12,702   |          |   |      | 1,428  |   |      |   | 512    |      |  |   | 1,614   |   |  |      | 6,795   |   |  |   | 3,750  |   |  |   | 14,316   |  
|Revisions of prior estimates, changes in price and other |  |                           | 19,021  |         |                           |   | 30,092 |         |   |   | (113,093 | )        |   |      | 133    |   |      |   | 10,828 |      |  |   | (12,724 | ) |  |      | 19,154  |   |  |   | 40,920 |   |  |   | (125,817 | )
|Net profits income                                       |  |                           | (10,991 | )       |                           |   | (7,813 | )       |   |   | (12,782  | )        |   |      | (1,953 | ) |      |   | (1,237 | )    |  |   | (1,607  | ) |  |      | (12,944 | ) |  |   | (9,050 | ) |  |   | (14,389  | )
|                                                         |  |                           |         |         |                           |   |        |         |   |   |          |          |   |      |        |   |      |   |        |      |  |   |         |   |  |      |         |   |  |   |        |   |  |   |          |  
|Standardized measure, December 31                        |  | $                         | 78,193  |         |                           | $ | 63,937 |         |   | $ | 38,093   |          |   | $    | 15,662 |   |      | $ | 16,054 |      |  | $ | 5,951   |   |  | $    | 93,855  |   |  | $ | 79,991 |   |  | $ | 44,044   |  
|                                                         |  |                           |         |         |                           |   |        |         |   |   |          |          |   |      |        |   |      |   |        |      |  |   |         |   |  |      |         |   |  |   |        |   |  |   |          |  
|                                                         |  |                           |         |         |                           |   |        |         |  
|Underlying Properties                                    |  |                           |         |         |                           |   |        |         |   |   |          |          |   |      |        |   |      |   |        |      |  |   |         |   |  |      |         |   |  |   |        |   |  |   |          |  
|                                                         |  |                           |        
|Standardized measure, January 1                          |  |                           | $       | 92,447  |                           |   | $      | 50,261  |   |   | $        | 192,401  |  
|                                                         |  |                           |         |         |                           |   |        |         |   |   |          |          |   |      |        |   |      |   |        |      |  |   |         |   |  |      |         |   |  |   |        |   |  |   |          |  
|Revisions:                                               |  |                           |         |         |                           |   |        |         |   |   |          |          |  
|Prices and costs                                         |  |                           |         | 15,737  |                           |   |        | 41,715  |   |   |          | (140,000 | )
|Quantity estimates                                       |  |                           |         | 5,717   |                           |   |        | 6,312   |   |   |          | (1,581   | )
|Accretion of discount                                    |  |                           |         | 7,867   |                           |   |        | 4,280   |   |   |          | 16,265   |  
|Future development costs                                 |  |                           |         | (148    | )                         |   |        | (101    | ) |   |          | (1,091   | )
|Other                                                    |  |                           |         | 7       |                           |   |        | (53     | ) |   |          | 49       |  
|                                                         |  |                           |         |         |                           |   |        |         |   |   |          |          |   |      |        |   |      |   |        |      |  |   |         |   |  |      |         |   |  |   |        |   |  |   |          |  
|Net revisions                                            |  |                           |         | 29,180  |                           |   |        | 52,153  |   |   |          | (126,358 | )
|Extensions, additions and discoveries                    |  |                           |         | 954     |                           |   |        | 363     |   |   |          | 563      |  
|Production                                               |  |                           |         | (14,965 | )                         |   |        | (10,902 | ) |   |          | (17,479  | )
|Development costs                                        |  |                           |         | 148     |                           |   |        | 572     |   |   |          | 1,134    |  
|                                                         |  |                           |         |         |                           |   |        |         |   |   |          |          |   |      |        |   |      |   |        |      |  |   |         |   |  |      |         |   |  |   |        |   |  |   |          |  
|Net change                                               |  |                           |         | 15,317  |                           |   |        | 42,186  |   |   |          | (142,140 | )
|                                                         |  |                           |         |         |                           |   |        |         |   |   |          |          |   |      |        |   |      |   |        |      |  |   |         |   |  |      |         |   |  |   |        |   |  |   |          |  
|                                                         |  |                           |        
|Standardized measure, December 31                        |  |                           | $       | 107,764 |                           |   | $      | 92,447  |   |   | $        | 50,261   |  
|                                                         |  |                           |         |         |                           |   |        |         |   |   |          |          |   |      |        |   |      |   |        |      |  |   |         |   |  |      |         |   |  |   |        |   |  |   |          |  



Reversion Agreement



Certain of the underlying royalties are subject to a reversion agreement
between XTO Energy and a third party. The agreement calls for XTO Energy to transfer 25% of its interest in those properties to the third party when amounts received by XTO Energy from the underlying properties subject to the agreement equal the
purchase price of the properties plus a 1% per month return on the unrecouped purchase price, known as payout. If payout were to occur and the 25% interest were to be transferred to the third party, the amounts payable to the trust would be
proportionately reduced. Based on 2003 prices and levels of production, XTO Energy has informed the trustee that payout is not projected to occur for approximately 15 years. Unless higher prices and production are sustained for several years, this
reversion agreement is not expected to have a material impact on the trust.



Regulation



Natural Gas Regulation



The interstate transportation and sale for resale of
natural gas is subject to federal regulation, including transportation rates charged and various other matters, by the Federal Energy Regulatory Commission (FERC). Federal price controls on wellhead sales of domestic natural gas terminated on
January 1, 1993. While natural gas prices are currently unregulated, Congress historically has been active in the area of natural gas regulation. It is impossible to predict whether new legislation to regulate natural gas might be proposed, what
proposals, if any, might actually be enacted by Congress or the various state legislatures, and what effect, if any, such proposals might have on the operations of the underlying properties.



8



---

State Regulation



The various states regulate the production and sale of oil and natural gas, including imposing requirements for obtaining
drilling permits, the method of developing new fields, the spacing and operation of wells and the prevention of waste of oil and gas resources. The rates of production may be regulated and the maximum daily production allowables from both oil and
gas wells may be established on a market demand or conservation basis, or both.



State Income Tax Withholding



Several states have enacted legislation to require state income tax withholding from nonresident royalty owners. After consultation with legal counsel, XTO Energy has advised the trustee that it believes the trust is not subject to these
withholding requirements. However, regulations are being developed or are subject to change by the various states, which could change this conclusion. In the event it is determined that the trust is required to withhold state taxes, distributions to
the unitholders would be reduced by the required amount, subject to the unitholders right to file a state tax return to claim any refund due.



Coal Seam Tax Credit



The trust receives net profits income from coal seam gas wells. Under Section 29 of the Internal Revenue Code, coal seam gas produced and sold through the
year 2002 from wells drilled after December 31, 1979 and prior to January 1, 1993 qualifies for the federal income tax credit for producing nonconventional fuels. This tax credit for 2003 was approximately $1.10 per MMBtu. Unitholders should be
entitled to this credit with respect to royalty income reported in 2003 relating to sales of qualifying production in 2002. This 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 is considering a new energy bill in 2004, but has not yet passed legislation that extends or renews the coal seam tax credit. Therefore, there currently is no significant benefit expected for future
years.



Other Regulation



The petroleum industry is also subject to compliance with various other
federal, state and local regulations and laws, including, but not limited to, regulations and laws relating to environmental protection, occupational safety, resource conservation and equal employment opportunity. 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.



Item 3.Legal Proceedings



Certain of the trust properties are involved in various lawsuits and certain governmental proceedings arising in the ordinary course of business. 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 2003.



9



---

PART II



Item 5.Market for Units of the Trust, Related Security Holder Matters and Trust Purchases of Units



The section entitled Units of Beneficial Interest in the
trusts annual report to unitholders for the year ended December 31, 2003 is incorporated herein by reference.



The trust has no equity compensation plans, nor has it purchased any units during the period covered by this report.



Item 6.Selected Financial Data



|                              |  |                        |            |      |   |            |  |      |            |      |   |            |  |   |           
|----------------------------- |  | ---------------------- | ---------- | ---- | - | ---------- |  | ---- | ---------- | ---- | - | ---------- |  | - | ----------
|                              |  | Year Ended December 31
|                              |  | 2003                   |            | 2002 |   | 2001       |  | 2000 |            | 1999
|Net Profits Income            |  | $                      | 12,944,047 |      | $ | 9,049,271  |  | $    | 14,389,316 |      | $ | 11,660,510 |  | $ | 6,691,336 
|Distributable Income          |  |                        | 12,688,746 |      |   | 8,822,310  |  |      | 14,209,884 |      |   | 11,502,114 |  |   | 6,549,803 
|Distributable Income per Unit |  |                        | 2.114791   |      |   | 1.470385   |  |      | 2.368314   |      |   | 1.917019   |  |   | 1.091635  
|Distributions per Unit        |  |                        | 2.114791   |      |   | 1.470385   |  |      | 2.368314   |      |   | 1.917019   |  |   | 1.091635  
|Total Assets at Year-End      |  |                        | 25,660,147 |      |   | 27,805,823 |  |      | 29,747,914 |      |   | 31,806,794 |  |   | 33,919,338



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, 2003
in the trusts annual report to unitholders for the year ended December 31, 2003 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 may borrow funds required to pay trust liabilities if fully repaid
prior to further distributions to unitholders.



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.



Off-Balance Sheet Arrangements



The trust has no off-balance sheet financing arrangements. 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, losses or contingent obligations.



Contractual Obligations



As shown below, the trust had no obligations and commitments to make future contractual payments as of December 31, 2003,
other than the December distribution payable to unitholders in January 2004, as reflected in the statement of assets, liabilities and trust corpus.



|                                    |  |                        |         |                  |   |           |  |           |   |                   |   |   |  |   |  
|----------------------------------- |  | ---------------------- | ------- | ---------------- | - | --------- |  | --------- | - | ----------------- | - | - |  | - | -
|                                    |  | Payments due by Period
|                                    |  | Total                  |         | Less than 1 Year |   | 13 Years |  | 35 Years |   | More than 5 Years
|Distribution payable to unitholders |  | $                      | 994,746 |                  | $ | 994,746   |  | $         |  |                   | $ |  |  | $ | 



10



---

Related Party Transactions



The underlying properties are currently owned by XTO Energy. XTO Energy deducts an overhead charge from monthly net proceeds
as reimbursement for costs associated with monitoring the 75% net profits interests. As of December 31, 2003, this monthly charge was $22,742 ($17,057 net to the trust) and is subject to annual adjustment based on an oil and gas industry index. For
further information regarding the trusts relationship with XTO Energy, see Note 5 to Financial Statements in the trusts annual report to unitholders for the year ended December 31, 2003.



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.



Basis of Accounting



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:



| |  |  | 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 certain contingencies that would not be recorded under generally accepted accounting principles.
| | - |  | ----------------------------------------------------------------------------------------------------------------------------------------------------



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, 2003.



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 nonexchange trade values.



Oil and Gas
Reserves



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 of the trusts Annual Report on Form 10-K, 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.



11



---

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, increased density drilling, maintenance projects, development, production and other costs, oil and gas prices, pricing differentials, proved reserves, payout on reversion properties, 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 on the 75% net profits interests properties 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 75% net profits interests. If development and production costs of the 75% net profits interests located 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 working interest 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.



12



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No Control Over the Operation or Development of Underlying
Properties.    Because XTO Energy does not operate most of the underlying properties, it is unable to significantly influence the operations or future development of the underlying properties. Neither the trustee nor the
trust unitholders can influence or control the operation or future development of the underlying properties. The current operators of the underlying properties are under no obligation to continue operating the properties. Neither the trustee nor
trust unitholders have the right to replace an operator.



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.



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 its 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 5, 2004 and Arthur Andersen LLP
dated March 19, 2002 appearing in the trusts annual report to unitholders for the year ended December 31, 2003 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, 2003.



Item 9A.Controls and Procedures



As of the end of the period covered by 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 Rules 13a-15 and 15d-15. 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. There has not been any change in the trusts internal control over financial reporting during the period
covered by this report that has materially affected, or is reasonably likely to materially affect, the trusts internal control over financial reporting.



13



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PART III



Item 10.Directors and Executive Officers of the Registrant



The trust has no directors, executive officers or audit committee. 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. The Securities and Exchange Commission has
taken the position that executive officers and directors of XTO Energy must also file initial ownership reports and reports of changes in beneficial ownership. 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, 2003.



Because the trust has no
employees, it does not have a code of ethics. Employees of the trustee, Bank of America, N.A., must comply with the banks code of ethics, a copy of which will be provided to unitholders, without charge, upon request by appointment at Bank of
America Plaza, 17thFloor, 901 Main Street, Dallas, Texas 75202.



Item 11.Executive Compensation



The trustee received the following annual compensation
from 2001 through 2003 as specified in the trust indenture:



|                               |  |      |  |                             
|------------------------------ |  | ---- |  | ----------------------------
|Name and Principal Position    |  | Year |  | Other AnnualCompensation (1)
|Bank of America, N.A., Trustee |  | 2003 |  | $6,472                      
|                               |  | 2002 |  | 4,525                       
|                               |  | 2001 |  | 7,195                       

---

|(1) |  | Under the trust indenture, the trustee is entitled to an administrative fee of: (i) 1/20 of 1% of the first $100 million of the annual gross revenue of the trust, and 1/30 of
1% of the annual gross revenue of the trust in excess of $100 million, and (ii) trustees standard hourly rates for time in excess of 300 hours annually.
|--- |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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 trustee is not aware of any person who beneficially owns more than 5% of the outstanding units.



(b)Security Ownership of Management.    The trust has no directors or executive officers. As of March 1, 2004, Bank
of America, N.A. owned, in various fiduciary capacities, 40,359 units with a shared right to vote 34,093 of these units and no right to vote 6,266 of these units. Bank of America, N.A. disclaims any beneficial interests in these units. The number of
units reflected in this paragraph includes units held by all branches of Bank of America, N.A.



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



14



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Item 13.Certain Relationships and Related Transactions



In computing net profits income paid to the trust for the 75% net profits
interests, XTO Energy deducts an overhead charge as reimbursement for costs associated with monitoring these interests. This charge at December 31, 2003 was $22,742 per month, or $272,904 annually (net to the trust of $17,057 per month or
$204,684 annually), and is subject to annual adjustment based on an oil and gas industry index.



See Item 11 for the remuneration received by the trustee from 2001 through 2003 and Item 12(b) for information concerning units owned by the trustee, Bank
of America, N.A., in various fiduciary capacities.



Item
14.Principal Accounting Fees and Services



Fees for services performed by KPMG LLP for the years ended December 31, 2003 and 2002 are:



|                   |  |      |        |      |   |       
|------------------ |  | ---- | ------ | ---- | - | ------
|                   |  | 2003 |        | 2002
|Audit fees         |  | $    | 32,000 |      | $ | 27,000
|Audit-related fees |  |      |       |      |   |      
|Tax fees           |  |      |       |      |   |      
|All other fees     |  |      |       |      |   |      
|                   |  |      |        |      |   |       
|                   |  | $    | 32,000 |      | $ | 27,000
|                   |  |      |        |      |   |       



As referenced in Item
10, above, the trust has no audit committee, and as a result, has no audit committee pre-approval policy with respect to fees paid to KPMG LLP.



PART IV



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



|(a) |  | The following documents are filed as a part of this report:
|--- |  | -----------------------------------------------------------



| | 1. |  | Financial Statements (incorporated by reference in Item 8 of this report)
| | -- |  | -------------------------------------------------------------------------



Independent Auditors Reports

Statements of Assets, Liabilities and Trust Corpus at December 31, 2003 and 2002

Statements of
Distributable Income for the years ended December 31, 2003, 2002 and 2001

Statements of Changes in Trust Corpus for the years ended
December 31, 2003, 2002 and 2001

Notes to Financial Statements



| | 2. |  | Financial Statement Schedules
| | -- |  | -----------------------------



Financial statement schedules are omitted because of the absence of conditions under which they are required or because the required information is given
in the financial statements or notes thereto.



15



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| | 3. |  | Exhibits
| | -- |  | --------



|       |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                            
|------ |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|       | 
|(4)(a) |  | Cross Timbers Royalty Trust Indenture amended and restated on January 13, 1992 by NationsBank, N.A. (now Bank of America, N.A.), as trustee, heretofore filed as Exhibit 3.1 to the
trusts Registration Statement No. 33-44385 filed with the Securities and Exchange Commission on February 19, 1992, is incorporated herein by reference.                                                                                                                                                                                                                                                                                                                               
|       | 
|(b)    |  | Net Overriding Royalty Conveyance (Cross Timbers Royalty Trust, 90%Texas) from South Timbers Limited Partnership, West Timbers Limited Partnership, North Timbers Limited Partnership,
East Timbers Limited Partnership, Hickory Timbers Limited Partnership, and Cross Timbers Partners, L.P. (predecessors of XTO Energy Inc.) to NCNB Texas National Bank (now Bank of America, N.A.), as trustee, dated February 12, 1991 (without Schedules
A and B), heretofore filed as Exhibit 10.1 to the trusts Registration Statement No. 33-44385 filed with the Securities and Exchange Commission on February 19, 1992, is incorporated herein by reference.               
|       | 
|(c)    |  | Correction to Net Overriding Royalty Conveyance (Cross Timbers Royalty Trust, 90%Texas) from South Timbers Limited Partnership, West Timbers Limited Partnership, North Timbers Limited
Partnership, East Timbers Limited Partnership, Hickory Timbers Limited Partnership, and Cross Timbers Partners, L.P. (predecessors of XTO Energy Inc.) to NCNB Texas National Bank (now Bank of America, N.A.), as trustee, dated September 23, 1991
(without Schedules A and B), heretofore filed as Exhibit 10.2 to the trusts Registration Statement No. 33-44385 filed with the Securities and Exchange Commission on February 19, 1992, is incorporated herein by reference.
|       | 
|(d)    |  | Net Overriding Royalty Conveyance (Cross Timbers Royalty Trust, 75%Texas) from South Timbers Limited Partnership, West Timbers Limited Partnership, North Timbers Limited Partnership,
East Timbers Limited Partnership, Hickory Timbers Limited Partnership, and Cross Timbers Partners, L.P. (predecessors of XTO Energy Inc.) to NCNB Texas National Bank (now Bank of America, N.A.), as trustee, dated February 12, 1991 (without Schedules
A and B), heretofore filed as Exhibit 10.5 to the trusts Registration Statement No. 33-44385 filed with the Securities and Exchange Commission on February 19, 1992, is incorporated herein by reference.               
|       | 
|(13)   |  | Cross Timbers Royalty Trust annual report to unitholders for the year ended December 31, 2003                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                              
|       | 
|(23.1) |  | Consent of KPMG LLP                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                        
|       | 
|(23.2) |  | Notice Regarding Consent of Arthur Andersen LLP                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                            
|       | 
|(23.3) |  | Consent of Miller and Lents, Ltd.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                          
|       | 
|(31)   |  | Rule 13a-14(a)/15d-14(a) Certification                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                     
|       | 
|(32)   |  | Section 1350 Certification                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                 



Copies of the above
Exhibits are available to any unitholder, at the actual cost of reproduction, upon written request to the trustee, Bank of America, N.A., P.O. Box 830650, Dallas, Texas 75283-0650.



|(b) |  | Reports on Form 8-K
|--- |  | -------------------



During the last quarter of the trusts fiscal year ended December 31, 2003, there were no reports filed on Form 8-K by the trust with the Securities
and Exchange Commission. The trust furnished three reports on Form 8-K under Item 12 for this period.



16



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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.



|                     |  |  |  |                                                               |  |                         |  |                                                                      
|-------------------- |  |  |  | ------------------------------------------------------------- |  | ----------------------- |  | ---------------------------------------------------------------------
|                     |  |  |  | CROSS TIMBERS ROYALTY TRUST By BANK OF AMERICA, N.A., TRUSTEE
|                     |  |  |  |                                                              
|                     |  |  |  |                                                               |  | By:                     |  | /s/    NANCY G. WILLIS                                               
|                     |  |  |  |                                                               |  |                         |  | Nancy G. Willis Vice President                                       
|                     |  | 
|                     |  |  |  | XTO ENERGY INC.                                              
|                     |  |  | 
|Date: March 11, 2004 |  |  |  | By:                                                           |  | /s/    LOUIS G. BALDWIN
|                     |  |  |  |                                                               |  |                         |  | Louis G. Baldwin Executive Vice President and Chief Financial Officer



(The trust has no
directors or executive officers.)



17