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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, 2004 |  | 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, 2004 (the last business day of its most recently completed second fiscal quarter), held by non-affiliates of the registrant on that date was approximately $159 million.



At February 28, 2005, 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:



2004 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 net profits interests conveyed 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. XTO Energy
currently 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 generally 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, as defined in the conveyances. 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, 2004 was $23,265 ($17,449 net to the
trust). XTO Energy also deducts an overhead charge as operator of the Penwell Unit. As of December 31, 2004, monthly overhead attributable to the Penwell Unit was $3,324 ($2,493 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



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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.



Approximately 20 of the underlying royalty interests in the San Juan Basin
burden working interests in properties operated by XTO Energy. As a result of an acquisition in August 2004, XTO Energy also became operator of the Penwell Unit which is one of the properties underlying the Texas 75% net profits interests.
Otherwise, XTO Energy does not operate or control any working interests associated with the underlying 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 69% of the net profits income received by the trust during 2004, as well as 68% of the estimated proved reserves of the net profits
interests at December 31, 2004 (based on estimated future net cash



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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.



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 million 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 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 23.9 Bcf at December 31, 2004, or approximately 80% of trust total gas reserves at that date. XTO Energy estimates that underlying royalties in the San Juan Basin include more than
3,900 gross (approximately 40 net) wells, covering over 60,000 gross acres. Approximately half 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 26% of the trusts 2004 gas sales volumes were from coal seam production in the San Juan Basin. Through 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 one to two wells per 320-acre spacing unit, doubling the number of drill wells allowed. Increasing the
density of coal seam wells could impact a significant portion of the trusts acreage. 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. In 1999, this formation was approved for increased density drilling, which doubled the number of drill wells allowed to four per spacing unit. XTO Energy has advised the trustee that the trust has received
net proceeds from additional Mesaverde wells in recent years and that it believes operators will continue to further develop the Mesaverde formation underlying the net profits interests.



Eastward pipeline capacity was added in the San Juan Basin in the recent past, reducing the dependence of this gas on
California markets and effectively increasing San Juan Basin gas prices in relation to prices from other regions. Gas-powered electricity generation is increasing in the southwest, and future pipelines are being discussed.



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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 major operators. 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:



|                        |  |                 |  |                              |  |                         |   |  |                 |  
|----------------------- |  | --------------- |  | ---------------------------- |  | ----------------------- | - |  | --------------- | -
|                        |  |                 |  |                              |  | Ownership of XTO Energy |  
|Unit                    |  | County/State    |  | Operator                     |  | 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     |  | XTO Energy Inc.              |  | 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, 2004, there were 1,488 gross (69.2 net) productive oil wells, 994 gross (39.9 net) water injection wells and two gross (0.2 net) wells in process of drilling
on these properties. Total wells drilled were seven gross (0.6 net) wells in 2004, 11 gross (0.2 net) wells in 2003 and nine gross (0.2 net) wells in 2002. These totals include no water injection wells drilled in 2004, six gross (0.1 net) in 2003
and four gross (0.1 net) in 2002.



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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, 2004 were
as follows:



|                       |  |                           |           |                           |   |           |  |      |           |      |   |         |  |      |         |      |   |         |  |   |           |  |   |           |  |   |          
|---------------------- |  | ------------------------- | --------- | ------------------------- | - | --------- |  | ---- | --------- | ---- | - | ------- |  | ---- | ------- | ---- | - | ------- |  | - | --------- |  | - | --------- |  | - | ---------
|                       |  | 90% Net Profits Interests |           | 75% Net Profits Interests |   | Total    
|                       |  | 2004                      |           | 2003                      |   | 2002      |  | 2004 |           | 2003 |   | 2002    |  | 2004 |         | 2003 |   | 2002   
|Production             |  |                           |           |                           |   |           |  |      |           |      |   |         |  |      |         |      |   |         |  |   |           |  |   |           |  |   |          
|                       |  |                           |           |                           |   |           |  |      |          
|Underlying Properties  |  |                           |           |                           |   |           |  |      |           |      |   |         |  |      |         |      |   |         |  |   |           |  |   |           |  |   |          
|                       |  |                           |           |                           |   |           |  |      |          
|OilSales (Bbls)       |  |                           | 72,038    |                           |   | 70,742    |  |      | 95,789    |      |   | 203,754 |  |      | 228,127 |      |   | 243,186 |  |   | 275,792   |  |   | 298,869   |  |   | 338,975  
|Average per day (Bbls) |  |                           | 197       |                           |   | 194       |  |      | 263       |      |   | 557     |  |      | 625     |      |   | 666     |  |   | 754       |  |   | 819       |  |   | 929      
|GasSales (Mcf)        |  |                           | 2,506,195 |                           |   | 2,604,146 |  |      | 2,947,897 |      |   | 78,619  |  |      | 73,314  |      |   | 82,052  |  |   | 2,584,814 |  |   | 2,677,460 |  |   | 3,029,949
|Average per day (Mcf)  |  |                           | 6,847     |                           |   | 7,135     |  |      | 8,076     |      |   | 215     |  |      | 201     |      |   | 225     |  |   | 7,062     |  |   | 7,336     |  |   | 8,301    
|                       |  |                           |           |                           |   |           |  |      |          
|Net Profits Interests  |  |                           |           |                           |   |           |  |      |           |      |   |         |  |      |         |      |   |         |  |   |           |  |   |           |  |   |          
|                       |  |                           |           |                           |   |           |  |      |          
|OilSales (Bbls)       |  |                           | 62,950    |                           |   | 59,781    |  |      | 85,017    |      |   | 73,658  |  |      | 70,736  |      |   | 53,232  |  |   | 136,608   |  |   | 130,517   |  |   | 138,249  
|Average per day (Bbls) |  |                           | 172       |                           |   | 164       |  |      | 233       |      |   | 201     |  |      | 194     |      |   | 146     |  |   | 373       |  |   | 358       |  |   | 379      
|GasSales (Mcf)        |  |                           | 2,242,031 |                           |   | 2,315,504 |  |      | 2,630,283 |      |   | 30,822  |  |      | 22,026  |      |   | 18,511  |  |   | 2,272,853 |  |   | 2,337,530 |  |   | 2,648,794
|Average per day (Mcf)  |  |                           | 6,126     |                           |   | 6,344     |  |      | 7,206     |      |   | 84      |  |      | 60      |      |   | 51      |  |   | 6,210     |  |   | 6,404     |  |   | 7,257    
|                       |  |                           |           |                           |   |           |  |      |          
|Average Sales Price    |  |                           |           |                           |   |           |  |      |           |      |   |         |  |      |         |      |   |         |  |   |           |  |   |           |  |   |          
|Oil (per Bbl)          |  | $                         | 35.62     |                           | $ | 28.95     |  | $    | 22.87     |      | $ | 35.70   |  | $    | 27.76   |      | $ | 22.10   |  | $ | 35.68     |  | $ | 28.04     |  | $ | 22.31    
|Gas (per Mcf)          |  | $                         | 5.79      |                           | $ | 4.89      |  | $    | 2.80      |      | $ | 4.02    |  | $    | 4.07    |      | $ | 2.48    |  | $ | 5.73      |  | $ | 4.86      |  | $ | 2.79     



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. The trust is entitled to 10% of oil and gas production attributable to the underlying
mineral interests, 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, 2004, 2003, 2002 and 2001. 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



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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. These costs are the legal obligation of XTO Energy as the owner of the underlying working interests
and will only be deducted from net proceeds payable to the trust if net proceeds from the related conveyance exceed such costs when paid, subject to excess cost carryforward provisions as described under Item 1. Business.



Year-end oil prices used to determine the standardized measure were based on
a West Texas Intermediate crude oil posted price of $40.25 per Bbl in 2004, $29.25 per Bbl in 2003, $28.00 per Bbl in 2002 and $16.75 per Bbl in 2001. The year-end weighted average realized gas prices used to determine the standardized measure were
$5.14 per Mcf in 2004, $5.15 per Mcf in 2003, $4.06 per Mcf in 2002 and $2.28 per Mcf in 2001.



Proved Reserves



|                                      |  |                          |   |  |                          |   |  |           |   |  |                       |   |  |           |   |  |           |   |  |           |   |  |           |  
|------------------------------------- |  | ------------------------ | - |  | ------------------------ | - |  | --------- | - |  | --------------------- | - |  | --------- | - |  | --------- | - |  | --------- | - |  | --------- | -
|                                      |  | Net Profits Interests    |   |  |                          |   |  |           |  
|(in thousands)                        |  | 90% Net ProfitsInterests |   |  | 75% Net ProfitsInterests |   |  | Total     |   |  | Underlying Properties |  
|                                      |  | Oil(Bbls)                |   |  | Gas (Mcf)                |   |  | Oil(Bbls) |   |  | Gas(Mcf)              |   |  | Oil(Bbls) |   |  | Gas (Mcf) |   |  | Oil(Bbls) |   |  | Gas (Mcf) |  
|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, additions and discoveries |  | 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, additions and discoveries |  | 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  |  
|Extensions, additions and discoveries |  | 2.1                      |   |  | 802.7                    |   |  | -0-       |   |  | -0-                   |   |  | 2.1       |   |  | 802.7     |   |  | 2.3       |   |  | 891.1     |  
|Revisions of prior estimates          |  | 71.0                     |   |  | 426.7                    |   |  | 154.0     |   |  | 66.2                  |   |  | 225.0     |   |  | 492.9     |   |  | 235.0     |   |  | 555.5     |  
|Production                            |  | (62.9                    | ) |  | (2,242.1                 | ) |  | (73.7     | ) |  | (30.8                 | ) |  | (136.6    | ) |  | (2,272.9  | ) |  | (275.8    | ) |  | (2,584.8  | )
|                                      |  |                          |   |  |                          |   |  |           |   |  |                       |   |  |           |   |  |           |   |  |           |   |  |           |  
|Balance, December 31, 2004            |  | 630.9                    |   |  | 29,628.5                 |   |  | 1,071.7   |   |  | 465.6                 |   |  | 1,702.6   |   |  | 30,094.1  |   |  | 3,457.4   |   |  | 34,155.8  |  
|                                      |  |                          |   |  |                          |   |  |           |   |  |                       |   |  |           |   |  |           |   |  |           |   |  |           |  



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 2002 were primarily the result of the higher year-end oil price used in estimating proved reserves. During 2002 and 2003, upward revisions of the 90% net profits interests proved gas reserves and the underlying
properties proved gas reserves were primarily because of lower than anticipated production declines and higher year-end gas prices. Extensions, additions and discoveries of the 90% net profits interests proved gas reserves and the underlying
properties proved gas reserves were higher in 2004 than in 2002 or 2003 primarily because of development in the Mesaverde formation of the San Juan Basin. See General above.



Proved Developed Reserves



|                  |  |                          |  |                          |  |           |  |                      |  |           |  |           |  |           |  |          
|----------------- |  | ------------------------ |  | ------------------------ |  | --------- |  | -------------------- |  | --------- |  | --------- |  | --------- |  | ---------
|                  |  | Net Profits Interests    |  |                          |  |          
|(in thousands)    |  | 90% Net ProfitsInterests |  | 75% Net ProfitsInterests |  | Total     |  | UnderlyingProperties
|                  |  | Oil(Bbls)                |  | Gas (Mcf)                |  | Oil(Bbls) |  | Gas(Mcf)             |  | Oil(Bbls) |  | Gas (Mcf) |  | Oil(Bbls) |  | Gas (Mcf)
|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 
|                  |  |                          |  |                          |  |           |  |                      |  |           |  |           |  |           |  |          
|December 31, 2004 |  | 630.9                    |  | 29,210.5                 |  | 1,071.6   |  | 465.6                |  | 1,702.5   |  | 29,676.1  |  | 3,457.4   |  | 33,691.3 
|                  |  |                          |  |                          |  |           |  |                      |  |           |  |           |  |           |  |          



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 |  
|                        |  | 2004                      |         |          | 2003                      |   |         | 2002        |   |   | 2004    |         |   | 2003 |         |   | 2002 |   |         | 2004 |  |   | 2003    |   |  | 2002 |         
|Net Profits Interests   |  |                           |         |          |                           |   |         |             |   |   |         |         |   |      |         |   |      |   |         |      |  |   |         |   |  |      |          |   |  |   |         |   |  |   |         |  
|                        |  |                           |         |          |                           |   |         |             |  
|Future cash inflows     |  | $                         | 177,911 |          |                           | $ | 178,591 |             |   | $ | 145,445 |         |   | $    | 45,192  |   |      | $ | 31,527  |      |  | $ | 32,474  |   |  | $    | 223,103  |   |  | $ | 210,118 |   |  | $ | 177,919 |  
|Future production taxes |  |                           | (13,894 | )        |                           |   | (14,267 | )           |   |   | (11,596 | )       |   |      | (3,045  | ) |      |   | (2,156  | )    |  |   | (2,212  | ) |  |      | (16,939  | ) |  |   | (16,423 | ) |  |   | (13,808 | )
|                        |  |                           |         |          |                           |   |         |             |   |   |         |         |   |      |         |   |      |   |         |      |  |   |         |   |  |      |          |   |  |   |         |   |  |   |         |  
|Future net cash flows   |  |                           | 164,017 |          |                           |   | 164,324 |             |   |   | 133,849 |         |   |      | 42,147  |   |      |   | 29,371  |      |  |   | 30,262  |   |  |      | 206,164  |   |  |   | 193,695 |   |  |   | 164,111 |  
|10% discount factor     |  |                           | (85,161 | )        |                           |   | (86,131 | )           |   |   | (69,912 | )       |   |      | (20,412 | ) |      |   | (13,709 | )    |  |   | (14,208 | ) |  |      | (105,573 | ) |  |   | (99,840 | ) |  |   | (84,120 | )
|                        |  |                           |         |          |                           |   |         |             |   |   |         |         |   |      |         |   |      |   |         |      |  |   |         |   |  |      |          |   |  |   |         |   |  |   |         |  
|Standardized measure    |  | $                         | 78,856  |          |                           | $ | 78,193  |             |   | $ | 63,937  |         |   | $    | 21,735  |   |      | $ | 15,662  |      |  | $ | 16,054  |   |  | $    | 100,591  |   |  | $ | 93,855  |   |  | $ | 79,991  |  
|                        |  |                           |         |          |                           |   |         |             |   |   |         |         |   |      |         |   |      |   |         |      |  |   |         |   |  |      |          |   |  |   |         |   |  |   |         |  
|Underlying Properties   |  |                           |         |          |                           |   |         |             |   |   |         |         |  
|                        |  |                           |        
|Future cash inflows     |  |                           | $       | 313,937  |                           |   | $       | 287,484     |   |   | $       | 250,219 |  
|Future production costs |  |                           |         | (75,500  | )                         |   |         | (65,741     | ) |   |         | (61,148 | )
|                        |  |                           |         |          |                           |   |         |             |   |   |         |         |   |      |         |   |      |   |         |      |  |   |         |   |  |      |          |   |  |   |         |   |  |   |         |  
|Future net cash flows   |  |                           |         | 238,437  |                           |   |         | 221,743     |   |   |         | 189,071 |  
|10% discount factor     |  |                           |         | (121,839 | )                         |   |         | (113,979    | ) |   |         | (96,624 | )
|                        |  |                           |         |          |                           |   |         |             |   |   |         |         |   |      |         |   |      |   |         |      |  |   |         |   |  |      |          |   |  |   |         |   |  |   |         |  
|Standardized measure    |  |                           | $       | 116,598  |                           |   | $       | 107,764     |   |   | $       | 92,447  |  
|                        |  |                           |         |          |                           |   |         |             |   |   |         |         |   |      |         |   |      |   |         |      |  |   |         |   |  |      |          |   |  |   |         |   |  |   |         |  



7



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





|                                                         |  |                           |         |         |                           |   |         |         |   |   |        |         |   |      |        |   |      |   |        |      |  |   |        |   |  |      |         |   |  |   |         |   |  |   |        |  
|-------------------------------------------------------- |  | ------------------------- | ------- | ------- | ------------------------- | - | ------- | ------- | - | - | ------ | ------- | - | ---- | ------ | - | ---- | - | ------ | ---- |  | - | ------ | - |  | ---- | ------- | - |  | - | ------- | - |  | - | ------ | -
|(in thousands)                                           |  | 90% Net Profits Interests |         |         | 75% Net Profits Interests |   |         | Total   |  
|                                                         |  | 2004                      |         |         | 2003                      |   |         | 2002    |   |   | 2004   |         |   | 2003 |        |   | 2002 |   |        | 2004 |  |   | 2003   |   |  | 2002 |        
|Net Profits Interests                                    |  |                           |         |         |                           |   |         |         |   |   |        |         |   |      |        |   |      |   |        |      |  |   |        |   |  |      |         |   |  |   |         |   |  |   |        |  
|                                                         |  |                           |         |         |                           |   |         |         |  
|Standardized measure,January 1                           |  | $                         | 78,193  |         |                           | $ | 63,937  |         |   | $ | 38,093 |         |   | $    | 15,662 |   |      | $ | 16,054 |      |  | $ | 5,951  |   |  | $    | 93,855  |   |  | $ | 79,991  |   |  | $ | 44,044 |  
|Extensions, additions and discoveries                    |  |                           | 1,906   |         |                           |   | 859     |         |   |   | 327    |         |   |      | -0-    |   |      |   | -0-    |      |  |   | -0-    |   |  |      | 1,906   |   |  |   | 859     |   |  |   | 327    |  
|Accretion of discount                                    |  |                           | 6,578   |         |                           |   | 5,367   |         |   |   | 3,238  |         |   |      | 1,398  |   |      |   | 1,428  |      |  |   | 512    |   |  |      | 7,976   |   |  |   | 6,795   |   |  |   | 3,750  |  
|Revisions of prior estimates, changes in price and other |  |                           | 4,732   |         |                           |   | 19,021  |         |   |   | 30,092 |         |   |      | 7,344  |   |      |   | 133    |      |  |   | 10,828 |   |  |      | 12,076  |   |  |   | 19,154  |   |  |   | 40,920 |  
|Net profits income                                       |  |                           | (12,553 | )       |                           |   | (10,991 | )       |   |   | (7,813 | )       |   |      | (2,669 | ) |      |   | (1,953 | )    |  |   | (1,237 | ) |  |      | (15,222 | ) |  |   | (12,944 | ) |  |   | (9,050 | )
|                                                         |  |                           |         |         |                           |   |         |         |   |   |        |         |   |      |        |   |      |   |        |      |  |   |        |   |  |      |         |   |  |   |         |   |  |   |        |  
|Standardized measure, December 31                        |  | $                         | 78,856  |         |                           | $ | 78,193  |         |   | $ | 63,937 |         |   | $    | 21,735 |   |      | $ | 15,662 |      |  | $ | 16,054 |   |  | $    | 100,591 |   |  | $ | 93,855  |   |  | $ | 79,991 |  
|                                                         |  |                           |         |         |                           |   |         |         |   |   |        |         |   |      |        |   |      |   |        |      |  |   |        |   |  |      |         |   |  |   |         |   |  |   |        |  
|                                                         |  |                           |         |         |                           |   |         |         |  
|Underlying Properties                                    |  |                           |         |         |                           |   |         |         |   |   |        |         |   |      |        |   |      |   |        |      |  |   |        |   |  |      |         |   |  |   |         |   |  |   |        |  
|                                                         |  |                           |        
|Standardized measure, January 1                          |  |                           | $       | 107,764 |                           |   | $       | 92,447  |   |   | $      | 50,261  |  
|                                                         |  |                           |         |         |                           |   |         |         |   |   |        |         |   |      |        |   |      |   |        |      |  |   |        |   |  |      |         |   |  |   |         |   |  |   |        |  
|Revisions:                                               |  |                           |         |         |                           |   |         |         |   |   |        |         |  
|Prices and costs                                         |  |                           |         | 14,539  |                           |   |         | 15,737  |   |   |        | 41,715  |  
|Quantity estimates                                       |  |                           |         | 882     |                           |   |         | 5,717   |   |   |        | 6,312   |  
|Accretion of discount                                    |  |                           |         | 9,149   |                           |   |         | 7,867   |   |   |        | 4,280   |  
|Future development costs                                 |  |                           |         | (339    | )                         |   |         | (148    | ) |   |        | (101    | )
|Other                                                    |  |                           |         | (7      | )                         |   |         | 7       |   |   |        | (53     | )
|                                                         |  |                           |         |         |                           |   |         |         |   |   |        |         |   |      |        |   |      |   |        |      |  |   |        |   |  |      |         |   |  |   |         |   |  |   |        |  
|Net revisions                                            |  |                           |         | 24,224  |                           |   |         | 29,180  |   |   |        | 52,153  |  
|Extensions, additions and discoveries                    |  |                           |         | 2,117   |                           |   |         | 954     |   |   |        | 363     |  
|Production                                               |  |                           |         | (17,846 | )                         |   |         | (14,965 | ) |   |        | (10,902 | )
|Development costs                                        |  |                           |         | 339     |                           |   |         | 148     |   |   |        | 572     |  
|                                                         |  |                           |         |         |                           |   |         |         |   |   |        |         |   |      |        |   |      |   |        |      |  |   |        |   |  |      |         |   |  |   |         |   |  |   |        |  
|Net change                                               |  |                           |         | 8,834   |                           |   |         | 15,317  |   |   |        | 42,186  |  
|                                                         |  |                           |         |         |                           |   |         |         |   |   |        |         |   |      |        |   |      |   |        |      |  |   |        |   |  |      |         |   |  |   |         |   |  |   |        |  
|Standardized measure, December 31                        |  |                           | $       | 116,598 |                           |   | $       | 107,764 |   |   | $      | 92,447  |  
|                                                         |  |                           |         |         |                           |   |         |         |   |   |        |         |   |      |        |   |      |   |        |      |  |   |        |   |  |      |         |   |  |   |         |   |  |   |        |  



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 2004 prices and levels of production, XTO Energy has informed the trustee that payout is not projected to occur for at least nine 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 recipients of oil and gas proceeds. After consultation with its state tax 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. Through 2002, sales of production from coal seam wells drilled from 1980 through 1992
qualified for a federal income tax credit under Section 29 of the Internal Revenue Code for nonconventional fuel sources. This federal income tax credit has not been extended.



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 underlying 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 2004.



9



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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, 2004 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
|                              |  | 2004                   |            | 2003 |   | 2002       |  | 2001 |            | 2000
|Net Profits Income            |  | $                      | 15,222,417 |      | $ | 12,944,047 |  | $    | 9,049,271  |      | $ | 14,389,316 |  | $ | 11,660,510
|Distributable Income          |  |                        | 14,924,058 |      |   | 12,688,746 |  |      | 8,822,310  |      |   | 14,209,884 |  |   | 11,502,114
|Distributable Income per Unit |  |                        | 2.487343   |      |   | 2.114791   |  |      | 1.470385   |      |   | 2.368314   |  |   | 1.917019  
|Distributions per Unit        |  |                        | 2.487343   |      |   | 2.114791   |  |      | 1.470385   |      |   | 2.368314   |  |   | 1.917019  
|Total Assets at Year-End      |  |                        | 24,284,184 |      |   | 25,660,147 |  |      | 27,805,823 |      |   | 29,747,914 |  |   | 31,806,794



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, 2004
in the trusts annual report to unitholders for the year ended December 31, 2004 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, 2004,
other than the December distribution payable to unitholders in January 2005, as shown 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 than5 Years
|Distribution payable to unitholders |  | $                      | 1,436,490 |                  | $ | 1,436,490 |  | $         |  |                  | $ |  |  | $ | 



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, 2004, this monthly charge was $23,265 ($17,449 net to the trust). XTO Energy also deducts an overhead charge as operator of the Penwell Unit. As
of December 31, 2004, monthly overhead attributable to the Penwell Unit was $3,324 ($2,493 net to the trust). These overhead charges are 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, 2004.



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.
| | - | ----------------------------------------------------------------------------------------------------------------------------------------------------



This comprehensive basis of accounting other than generally accepted
accounting principles corresponds to the accounting permitted for royalty trusts by the U.S. Securities and Exchange Commission, as specified by Staff Accounting Bulletin Topic 12:E, Financial Statements of Royalty Trusts. 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, 2004.



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 proved oil and gas reserves for the underlying properties are estimated by independent petroleum engineers. 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. 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.





11



---

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.



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 Expense and Development Costs.    Production expense 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 expense 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 costs and production expense 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 variances 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.



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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 expense in calculating net proceeds payable to the trust.



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 14, 2005, appearing in the trusts annual report to unitholders for the year ended December 31, 2004, are incorporated herein by reference.



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



There have
been no changes in accountants and no disagreements with the trusts independent registered public accountants on any matter of accounting principles or practices or financial statement disclosures during the two years ended December 31, 2004.



Item 9A.Controls and
Procedures



Conclusion Regarding the
Effectiveness of Disclosure Controls and Procedures



The
trustee conducted an evaluation of the trusts disclosure controls and procedures, as such term is defined under Rule 13a-15(e) promulgated under the Securities Exchange Act of 1934, as amended. Based on



13



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this evaluation, the trustee has concluded that the trusts disclosure controls and procedures were effective as of the end of the period covered by
this annual report. In its evaluation of disclosure controls and procedures, the trustee has relied, to the extent considered reasonable, on information provided by XTO Energy.



Trustees Report on Internal Control Over Financial Reporting



The trustee, Bank of America, N.A., is responsible for establishing and
maintaining adequate internal control over financial reporting, as such term is defined in Rule 13a-15(f) promulgated under the Securities Exchange Act of 1934, as amended. The trustee conducted an evaluation of the effectiveness of the trusts
internal control over financial reporting based on the criteria established in Internal ControlIntegrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on the trustees evaluation
under the framework in Internal ControlIntegrated Framework, the trustee concluded that the trusts internal control over financial reporting was effective as of December 31, 2004. The trustees assessment of the effectiveness
of the trusts internal control over financial reporting as of December 31, 2004 has been audited by KPMG LLP, an independent registered public accounting firm, as stated in their report included in the trusts annual report to unitholders
for the year ended December 31, 2004 which is incorporated herein by reference.



There were no changes in the trusts internal control over financial reporting during the quarter ended December 31, 2004 that have materially affected, or are reasonably likely to materially affect, the
trusts internal control over financial reporting.



Item
9B.Other Information



None.



14



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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, 2004.



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 2002 through 2004 as specified in the trust indenture:





|                               |  |      |  |                               |      
|------------------------------ |  | ---- |  | ----------------------------- | -----
|Name and Principal Position    |  | Year |  | Other Annual Compensation (1)
|Bank of America, N.A., Trustee |  | 2004 |  | $                             | 7,611
|                               |  | 2003 |  |                               | 6,472
|                               |  | 2002 |  |                               | 4,525

---

|(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 3, 2005, Bank of
America, N.A. owned, in various fiduciary capacities, 39,558 units, with a shared right to vote 26,892 of these units and no right to vote 12,666 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.





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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, 2004 was $23,265 per month, or $279,180 annually (net to the trust of $17,449 per month or
$209,388 annually). XTO Energy also deducts an overhead charge as operator of the Penwell Unit, one of the working interests underlying the Texas 75% net profits interests. As of December 31, 2004, overhead attributable to the Penwell Unit was
$3,324 per month, or $39,888 annually (net to the trust of $2,493 per month or $29,916 annually). These overhead charges are subject to annual adjustment based on an oil and gas industry index.



See Item 11 for the remuneration received by the trustee from 2002 through
2004 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, 2004 and 2003 are:



|                   |  |      |         |     |      |   |       
|------------------ |  | ---- | ------- | --- | ---- | - | ------
|                   |  | 2004 |         |     | 2003
|Audit fees         |  | $    | 76,206  | (1) |      | $ | 32,000
|Audit-related fees |  |      |        |     |      |   |      
|Tax fees           |  |      |        |     |      |   |      
|All other fees     |  |      |        |     |      |   |      
|                   |  |      |         |     |      |   |       
|                   |  |      | $76,206 |     |      | $ | 32,000
|                   |  |      |         |     |      |   |       

---

|(1) | Includes fees of $39,206 related to audit of the trusts internal control over financial reporting.
|--- | ---------------------------------------------------------------------------------------------------



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 and Financial
Statement Schedules



|(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 Registered Public Accounting Firm Reports

Statements of Assets, Liabilities and Trust Corpus at December 31, 2004 and 2003

Statements of Distributable Income for the years ended December 31, 2004, 2003 and 2002

Statements of Changes in Trust Corpus for the years ended December 31, 2004, 2003 and 2002

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.



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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, 2004                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                              
|       | 
|(23.1) |  | Consent of KPMG LLP                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                        
|       | 
|(23.2) |  | 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.



17



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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 14, 2005 |  |  |  | By              |  | /s/ LOUIS G. BALDWIN
|                     |  |  |  |                 |  |                      |  | Louis G. Baldwin Executive Vice President and Chief Financial Officer



(The trust has no
directors or executive officers.)





18