---



UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549



---



FORM 10-K



ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF

THE SECURITIES EXCHANGE ACT OF 1934



|                                            |  |                               
|------------------------------------------- |  | ------------------------------
|For the fiscal year ended December 31, 2005 |  | 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 if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ̈No x



Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ̈No x



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 a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of accelerated filer and large accelerated filer in Rule 12b-2 of the Exchange Act (check one):

Large accelerated filer ̈Accelerated filer x     Non-accelerated filer ̈



Indicate by check mark whether the registrant is a
shell company (as defined in Exchange Act Rule 12b-2). Yes ̈No x



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, 2005 (the last business day of its most recently completed second fiscal quarter), held by non-affiliates of
the registrant on that date was approximately $232 million.



At
February 28, 2006, 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:



2005 Annual Report to UnitholdersPart II



---



---



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. (formerly known as Cross Timbers Oil Company), 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 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, 2005 was $24,080
($18,060 net to the trust). XTO Energy also deducts an overhead charge as operator of the Penwell Unit. As of December 31, 2005, monthly overhead attributable to the Penwell Unit was $2,392 ($1,794 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 underlying properties. If at any time the trust receives net profits
income in excess of the amount due, the trust is not obligated to return the



1



---

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. XTO Energy also operates the Penwell Unit, following its acquisition of an additional interest in this unit in August 2004. XTO Energys original interest in the Penwell Unit is one
of the properties underlying the Texas 75% net profits interests. Other than these properties, XTO Energy does not operate or control any of the underlying properties or related working interests.



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 65% of the net profits income received by the trust during 2005, as well as 69% of the estimated proved reserves of the net profits
interests at December 31, 2005 (based on estimated future net cash flows using year-end oil and gas prices), is attributable to natural gas. There is generally a greater demand for gas during the winter. Otherwise, trust income is not subject
to seasonal factors, nor dependent upon patents, licenses, franchises or concessions. The trust conducts no research activities.



2



---

Item 1A.Risk Factors



The following factors, among others, could cause actual results to differ
materially from those contained in forward-looking statements made in this report and presented elsewhere by the trustee from time to time. Such factors, among others, may have a material adverse effect upon the trusts financial condition,
distributable income and changes in trust corpus.



The
following discussion of risk factors should be read in conjunction with the financial statements and related notes included in the trusts annual report to unitholders for the year ended December 31, 2005. Because of these and other
factors, past financial performance should not be considered an indication of future performance.



The market price for the trust units may not reflect the value of the net profits interests held by the trust.



The public trading price for the trust units tends to be tied to the recent and expected levels of cash distributions on the trust units. The amounts
available for distribution by the trust vary in response to numerous factors outside the control of the trust or XTO Energy, including prevailing prices for oil and natural gas produced from the underlying properties. The market price of the trust
units is not necessarily indicative of the value that the trust would realize if the net profits interests were sold to a third party buyer. In addition, such market price is not necessarily reflective of the fact that, since the assets of the trust
are depleting assets, a portion of each cash distribution paid on the trust units should be considered by investors as a return of capital, with the remainder being considered as a return on investment. There is no guarantee that distributions made
to a unitholder over the life of these depleting assets will equal or exceed the purchase price paid by the unitholder.



Oil and natural gas prices fluctuate due to a number of uncontrollable factors, and any decline will adversely affect the net proceeds payable to the trust and
trust distributions.



The trusts monthly cash
distributions are highly dependent upon the prices realized from the sale of natural gas and, to a lesser extent, oil. Oil and natural 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 domestic and foreign oil and natural gas,
consumer demand, the price and availability of alternative fuels, the proximity to, and capacity of, transportation facilities and the effect of worldwide energy conservation measures. Moreover, government regulations, such as regulation of natural
gas transportation and price controls, can affect product prices in the long term. Lower oil and natural gas prices may reduce the amount of oil and natural 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.



Higher production expense and/or development costs, without concurrent increases in revenue, will directly decrease the net proceeds payable to the trust from the properties underlying the 75% net profits
interests.



Production expense and development costs
are deducted in the calculation of the trusts share of net proceeds from properties underlying the 75% net profits interests. 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 for properties underlying the 75% net profits 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.



Proved
reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in reserve estimates or underlying assumptions could cause the quantities and net present value of the reserves to be overstated.



Estimating proved oil and gas reserves is inherently
uncertain. Petroleum engineers consider many factors and make assumptions in estimating reserves and future net cash flows. Those factors and assumptions include



3



---

historical production from the area compared with production rates from similar producing areas, the effects of governmental regulation, assumptions about
future commodity prices, production expense and development costs, taxes and capital expenditures, the availability of enhanced recovery techniques and relationships with landowners, working interest partners, pipeline companies and others. 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. Because the trust owns net
profits interests, it does not own a specific percentage of the oil and gas reserves. Estimated proved reserves for the net profits interests are based on estimates of reserves for the underlying properties and an allocation method that considers
estimated future net proceeds and oil and gas prices. Increases or decreases in oil and gas prices directly increase or decrease estimated reserves of the 75% net profits interests.



Operational risks and hazards associated with the development of the underlying properties may decrease trust distributions.



There are operational risks and hazards associated
with the production and transportation of oil and natural gas, including without limitation natural disasters, blowouts, explosions, fires, leakage of oil or natural gas, releases of other hazardous materials, mechanical failures, cratering, and
pollution. Any of these or similar occurrences could result in the interruption or cessation of operations, personal injury or loss of life, property damage, damage to productive formations or equipment, damage to the environment or natural
resources, or cleanup obligations. The operation of oil and gas properties is also subject to various laws and regulations. Non-compliance with such laws and regulations could subject the operator to additional costs, sanctions or liabilities. The
uninsured costs resulting from any of the above or similar occurrences could be deducted as a production expense or development cost in calculating the net proceeds payable to the trust from properties underlying the 75% net profits interests, and
would therefore reduce trust distributions by the amount of such uninsured costs.



Trust unitholders and the trustee have no influence over the operations on, or future development of, the 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 failure of an operator to conduct its operations or discharge its obligations in a
proper manner could have an adverse effect on the net proceeds payable to the trust. 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.



The assets of the trust represent
interests in depleting assets and, if XTO Energy and any other operators developing the underlying properties do not perform additional development projects, the assets may deplete faster than expected. Eventually, the assets of the trust will cease
to produce in commercial quantities and the trust will cease to receive proceeds from such assets.



The net proceeds payable to the trust are derived from the sale of depleting assets. Eventually, the properties underlying the trusts net profits
interests will cease to produce in commercial quantities and the trust will, therefore, cease to receive any net proceeds therefrom. 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 natural gas. If XTO Energy or other 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 estimated.



Terrorism and continued geopolitical hostilities could adversely affect trust distributions or the market price of the trust units.



Terrorist attacks and the threat of terrorist attacks, whether domestic or
foreign, as well as the military or other actions taken in response, cause instability in the global financial and energy markets. Terrorism and other



4



---

geopolitical hostilities could adversely affect trust distributions or the market price of the trust units in unpredictable ways, including through the
disruption of fuel supplies and markets, increased volatility in oil and natural gas prices, or the possibility that the infrastructure on which the operators of the underlying properties rely could be a direct target or an indirect casualty of an
act of terror.



XTO Energy may transfer its interest in the underlying
properties without the consent of the trust or the trust unitholders.



XTO Energy may at any time transfer all or part of its interest in the underlying properties to another party. Neither the trust nor the trust unitholders are entitled to vote on any transfer of the properties
underlying the trusts net profits interests, and the trust will not receive any proceeds of any such transfer. Following any transfer, the transferred property will continue to be subject to the net profits interests of the trust, but the
calculation, reporting and remitting of net proceeds to the trust will be the responsibility of the transferee.



In January 2006, XTO Energy announced that it will consider selling the underlying properties. Any sale is dependent upon XTO Energys ability to
structure a tax-efficient transaction and receive sufficient consideration from a buyer it deems to be qualified.



The operators of any underlying property may abandon the property, thereby terminating the related net profits interest payable to the trust.



The operators of the underlying properties, or any transferee thereof, may
abandon any well or property without the consent of the trust or the trust unitholders if they reasonably believe that the well or property can no longer produce in commercially economic quantities. This could result in the termination of the net
profits interest relating to the abandoned well or property.



The net
profits interests can be sold and the trust would be terminated.



The trust may sell the net profits interests if the holders of 80% or more of the trust units approve the sale or vote to terminate the trust. The trust will terminate if it fails to generate gross proceeds from the
underlying properties of at least $1,000,000 per year over any consecutive two-year period. Sale of all of the net profits interests will terminate the trust. The net proceeds of any sale must be for cash with the proceeds promptly distributed
to the trust unitholders.



Trust unitholders have limited voting
rights and have limited ability to enforce the trusts rights against the current or any future operators of the underlying properties.



The voting rights of a trust unitholder are more limited than those of stockholders of most public corporations. For example, there is no requirement for
annual meetings of trust unitholders or for an annual or other periodic re-election of the trustee. Additionally, trust unitholders have no voting rights in XTO Energy.



The trust indenture and related trust law permit the trustee and the trust to sue XTO Energy or operators of the underlying
properties to compel them to fulfill the terms of the conveyance of the net profits interests. If the trustee does not take appropriate action to enforce provisions of the conveyance, the recourse of the trust unitholders would likely be limited to
bringing a lawsuit against the trustee to compel the trustee to take specified actions. Trust unitholders probably would not be able to sue XTO Energy or operators of the underlying properties.



Financial information of the trust is not prepared in accordance with GAAP.



The financial statements of the trust are prepared on
a modified cash basis of accounting, which is a comprehensive basis of accounting other than accounting principles generally accepted in the U.S., or GAAP. Although this basis of accounting is permitted for royalty trusts by the Securities and
Exchange Commission, the financial statements of the trust differ from GAAP financial statements because net profits income is not accrued in the month of production, expenses are not recognized when incurred and cash reserves may be established for
certain contingencies that would not be recorded in GAAP financial statements.



5



---

The limited liability of trust unitholders is uncertain.



The trust unitholders are not protected from the liabilities of the trust to
the same extent that a shareholder would be protected from a corporations liabilities. The structure of the trust does not include the interposition of a limited liability entity such as a corporation or limited partnership which would provide
further limited liability protection to trust unitholders. While the trustee is liable for any excess liabilities incurred if the trustee fails to insure that such liabilities are to be satisfied only out of trust assets, under the laws of Texas,
which are unsettled on this point, a unitholder may be jointly and severally liable for any liability of the trust if the satisfaction of such liability was not contractually limited to the assets of the trust and the assets of the trust and the
trustee are not adequate to satisfy such liability. As a result, trust unitholders may be exposed to personal liability. The trust, however, is not liable for production costs or other liabilities of the underlying properties.



Drilling oil and natural gas wells is a high-risk activity and subjects the trust to a
variety of factors that it cannot control.



Drilling
oil and natural gas wells, including development wells, involves numerous risks, including the risk that commercially productive oil and natural gas reservoirs are not encountered. The presence of unanticipated pressures or irregularities in
formations, miscalculations or accidents may cause drilling activities to be unsuccessful. In addition, there is often uncertainty as to the future cost or timing of drilling, completing and operating wells. Further, the development activities may
be curtailed, delayed or canceled as a result of a variety of factors, including:



| |  |  | unexpected drilling conditions;
| | - |  | -------------------------------

| |  |  | title problems;
| | - |  | ---------------

| |  |  | restricted access to land for drilling or laying pipeline;
| | - |  | ----------------------------------------------------------

| |  |  | pressure or irregularities in formations;
| | - |  | -----------------------------------------

| |  |  | equipment failures or accidents;
| | - |  | --------------------------------

| |  |  | adverse weather conditions; and
| | - |  | -------------------------------

| |  |  | costs of, or shortages or delays in the availability of, drilling rigs, tubular materials and equipment.
| | - |  | --------------------------------------------------------------------------------------------------------



While these risks do not expose the trust to liabilities of the driller or operator of the well, they can reduce net
proceeds payable to the trust and trust distributions by decreasing oil and gas revenues or increasing production expense or development costs from the underlying properties. Furthermore, these risks may cause the costs of development activities on
properties underlying the 75% net profits interests to exceed the revenues therefrom, thereby reducing net proceeds payable to the trust and trust distributions.



The underlying properties are subject to complex federal, state and local laws and regulations that could adversely affect net
proceeds payable to the trust and trust distributions.



Extensive federal, state and local regulation of the oil and natural gas industry significantly affects operations on the underlying properties. In particular, oil and natural gas development and production are subject to stringent
environmental regulations. These regulations have increased the costs of planning, designing, drilling, installing, operating and abandoning oil and natural gas wells and other related facilities, which costs could reduce net proceeds payable to the
trust and trust distributions. These regulations may become more demanding in the future.



Item 1B.Unresolved Staff Comments



As of December 31, 2005, the trust did not have any unresolved Securities and Exchange Commission staff comments.



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



6



---

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. In January 2006, XTO Energy announced that it will
consider selling its interests in the underlying properties that are subject to the Cross Timbers Royalty Trust net profits interests. Any sale is dependent upon XTO Energys ability to structure a tax-efficient transaction and receive
sufficient consideration from a buyer it deems to be qualified.



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 23.7 Bcf at December 31, 2005, or approximately 81% of trust total gas reserves at that date. XTO Energy estimates that
underlying royalties in the San Juan Basin include more than 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 22% of the trusts 2005 gas sales volumes were from coal seam production in the San Juan Basin. In October 2002, regulatory authorities
approved increasing the density of coal seam wells drilled in the San Juan Basin from one well 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.



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.



7



---

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                      |  | Working Interest        |  | Revenue Interest
|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    |  | Occidental Permian, Ltd.      |  | 4.3%                    |  | 2.8%            
|Hewitt                  |  | Carter/Oklahoma |  | ExxonMobil Corporation        |  | 11.3%                   |  | 9.9%            
|Wildcat Jim Penn        |  | Carter/Oklahoma |  | Noble Energy Production, Inc. |  | 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, 2005, there were 1,521 gross (71.6 net) productive oil wells and seven gross (0.1 net) wells in process of drilling on these properties. Total wells
drilled were five gross (0.4 net) wells in 2005, seven gross (0.6 net) wells in 2004 and five gross (0.1 net) wells in 2003.



Oil and Natural 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, 2005 were as
follows:



|                       |  |                           |           |                           |   |           |  |      |           |      |   |         |  |      |         |      |   |         |  |   |           |  |   |           |  |   |          
|---------------------- |  | ------------------------- | --------- | ------------------------- | - | --------- |  | ---- | --------- | ---- | - | ------- |  | ---- | ------- | ---- | - | ------- |  | - | --------- |  | - | --------- |  | - | ---------
|                       |  | 90% Net Profits Interests |           | 75% Net Profits Interests |   | Total    
|                       |  | 2005                      |           | 2004                      |   | 2003      |  | 2005 |           | 2004 |   | 2003    |  | 2005 |         | 2004 |   | 2003   
|Production             |  |                           |           |                           |   |           |  |      |           |      |   |         |  |      |         |      |   |         |  |   |           |  |   |           |  |   |          
|                       |  |                           |           |                           |   |           |  |      |          
|Underlying Properties  |  |                           |           |                           |   |           |  |      |           |      |   |         |  |      |         |      |   |         |  |   |           |  |   |           |  |   |          
|                       |  |                           |           |                           |   |           |  |      |          
|OilSales (Bbls)       |  |                           | 69,784    |                           |   | 72,038    |  |      | 70,742    |      |   | 200,741 |  |      | 203,754 |      |   | 228,127 |  |   | 270,525   |  |   | 275,792   |  |   | 298,869  
|Average per day (Bbls) |  |                           | 191       |                           |   | 197       |  |      | 194       |      |   | 550     |  |      | 557     |      |   | 625     |  |   | 741       |  |   | 754       |  |   | 819      
|GasSales (Mcf)        |  |                           | 2,157,785 |                           |   | 2,506,195 |  |      | 2,604,146 |      |   | 94,576  |  |      | 78,619  |      |   | 73,314  |  |   | 2,252,361 |  |   | 2,584,814 |  |   | 2,677,460
|Average per day (Mcf)  |  |                           | 5,912     |                           |   | 6,847     |  |      | 7,135     |      |   | 259     |  |      | 215     |      |   | 201     |  |   | 6,171     |  |   | 7,062     |  |   | 7,336    
|                       |  |                           |           |                           |   |           |  |      |          
|Net Profits Interests  |  |                           |           |                           |   |           |  |      |           |      |   |         |  |      |         |      |   |         |  |   |           |  |   |           |  |   |          
|                       |  |                           |           |                           |   |           |  |      |          
|OilSales (Bbls)       |  |                           | 60,068    |                           |   | 62,950    |  |      | 59,781    |      |   | 85,630  |  |      | 73,658  |      |   | 70,736  |  |   | 145,698   |  |   | 136,608   |  |   | 130,517  
|Average per day (Bbls) |  |                           | 164       |                           |   | 172       |  |      | 164       |      |   | 235     |  |      | 201     |      |   | 194     |  |   | 399       |  |   | 373       |  |   | 358      
|GasSales (Mcf)        |  |                           | 1,925,342 |                           |   | 2,242,031 |  |      | 2,315,504 |      |   | 40,234  |  |      | 30,822  |      |   | 22,026  |  |   | 1,965,576 |  |   | 2,272,853 |  |   | 2,337,530
|Average per day (Mcf)  |  |                           | 5,275     |                           |   | 6,126     |  |      | 6,344     |      |   | 110     |  |      | 84      |      |   | 60      |  |   | 5,385     |  |   | 6,210     |  |   | 6,404    
|                       |  |                           |           |                           |   |           |  |      |          
|Average Sales Price    |  |                           |           |                           |   |           |  |      |           |      |   |         |  |      |         |      |   |         |  |   |           |  |   |           |  |   |          
|Oil (per Bbl)          |  | $                         | 50.34     |                           | $ | 35.62     |  | $    | 28.95     |      | $ | 49.47   |  | $    | 35.70   |      | $ | 27.76   |  | $ | 49.70     |  | $ | 35.68     |  | $ | 28.04    
|Gas (per Mcf)          |  | $                         | 7.87      |                           | $ | 5.79      |  | $    | 4.89      |      | $ | 5.09    |  | $    | 4.02    |      | $ | 4.07    |  | $ | 7.76      |  | $ | 5.73      |  | $ | 4.86     



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



8



---

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.



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, 2005, 2004, 2003 and 2002. The estimated reserves for the underlying properties are then used by XTO Energy to calculate the estimated oil and gas reserves attributable to the net profits interests. Numerous uncertainties are
inherent in estimating reserve volumes and values, and such estimates are subject to change as additional information becomes available. The reserves actually recovered and the timing of production of these reserves may be substantially different
from the original estimates.



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



Year-end oil prices
used to determine the standardized measure were based on a West Texas Intermediate crude oil posted price of $57.75 per Bbl in 2005, $40.25 per Bbl in 2004, $29.25 per Bbl in 2003 and $28.00 per Bbl in 2002. The year-end weighted average realized
gas prices used to determine the standardized measure were $7.70 per Mcf in 2005, $5.14 per Mcf in 2004, $5.15 per Mcf in 2003 and $4.06 per Mcf in 2002.



9



---

Proved 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) |  
|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  |  
|Extensions, additions and discoveries |  | 6.8                      |   |  | 702.7                    |   |  | -0-       |   |  | -0-                  |   |  | 6.8       |   |  | 702.7     |   |  | 7.6       |   |  | 780.6     |  
|Revisions of prior estimates          |  | (76.7                    | ) |  | 162.3                    |   |  | 204.1     |   |  | 79.1                 |   |  | 127.4     |   |  | 241.4     |   |  | 104.9     |   |  | 257.6     |  
|Production                            |  | (60.1                    | ) |  | (1,925.4                 | ) |  | (85.6     | ) |  | (40.2                | ) |  | (145.7    | ) |  | (1,965.6  | ) |  | (270.5    | ) |  | (2,252.4  | )
|                                      |  |                          |   |  |                          |   |  |           |   |  |                      |   |  |           |   |  |           |   |  |           |   |  |           |  
|Balance, December 31, 2005            |  | 500.9                    |   |  | 28,568.1                 |   |  | 1,190.2   |   |  | 504.5                |   |  | 1,691.1   |   |  | 29,072.6  |   |  | 3,299.4   |   |  | 32,941.6  |  
|                                      |  |                          |   |  |                          |   |  |           |   |  |                      |   |  |           |   |  |           |   |  |           |   |  |           |  



During 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 and 2005 than in 2003 primarily because of development in the San Juan Basin. See General above. As of
December 31, 2005, proved reserves for the underlying properties and attributable to the 90% net profits interests have been reduced to reflect anticipated payout under the reversion agreement in which 25% of XTO Energys interest in
certain underlying royalties will transfer to a third party when payout occurs. See Reversion Agreement below. This is the first time estimated proved reserves have been adjusted for the effect of the reversion agreement, since
anticipated payout has recently been accelerated by higher product prices and increased development of properties subject to the reversion agreement. The effect of anticipated payout was to reduce gas reserves for the underlying properties and net
profits interests by approximately 2%, oil reserves for the underlying properties by approximately 4% and oil reserves for the net profits interests by approximately 6%. The effect of the reversion agreement is included in 2005 revisions and is
offset by increased reserves related to higher year-end product prices.



Proved Developed Reserves



|                  |  |                           |  |                           |  |           |  |                      |  |           |  |           |  |           |  |          
|----------------- |  | ------------------------- |  | ------------------------- |  | --------- |  | -------------------- |  | --------- |  | --------- |  | --------- |  | ---------
|                  |  | Net Profits Interests     |  |                           |  |          
|(in thousands)    |  | 90% Net Profits Interests |  | 75% Net Profits Interests |  | Total     |  | UnderlyingProperties
|                  |  | Oil(Bbls)                 |  | Gas (Mcf)                 |  | Oil(Bbls) |  | Gas(Mcf)             |  | Oil(Bbls) |  | Gas (Mcf) |  | Oil(Bbls) |  | Gas (Mcf)
|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                  |  | 1,071.7   |  | 465.6                |  | 1,702.6   |  | 29,676.1  |  | 3,457.4   |  | 33,691.3 
|                  |  |                           |  |                           |  |           |  |                      |  |           |  |           |  |           |  |          
|December 31, 2005 |  | 500.9                     |  | 28,568.1                  |  | 1,190.2   |  | 504.5                |  | 1,691.1   |  | 29,072.6  |  | 3,299.4   |  | 32,941.6 
|                  |  |                           |  |                           |  |           |  |                      |  |           |  |           |  |           |  |          



10



---

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 |  
|                        |  | 2005                      |          |          | 2004                      |   |         | 2003        |   |   | 2005    |          |   | 2004 |         |   | 2003 |   |         | 2005 |  |   | 2004    |   |  | 2003 |         
|Net Profits Interests   |  |                           |          |          |                           |   |         |             |   |   |         |          |   |      |         |   |      |   |         |      |  |   |         |   |  |      |          |   |  |   |          |   |  |   |         |  
|                        |  |                           |          |          |                           |   |         |             |  
|Future cash inflows     |  | $                         | 250,137  |          |                           | $ | 177,911 |             |   | $ | 178,591 |          |   | $    | 68,872  |   |      | $ | 45,192  |      |  | $ | 31,527  |   |  | $    | 319,009  |   |  | $ | 223,103  |   |  | $ | 210,118 |  
|Future production taxes |  |                           | (21,274  | )        |                           |   | (13,894 | )           |   |   | (14,267 | )        |   |      | (4,828  | ) |      |   | (3,045  | )    |  |   | (2,156  | ) |  |      | (26,102  | ) |  |   | (16,939  | ) |  |   | (16,423 | )
|                        |  |                           |          |          |                           |   |         |             |   |   |         |          |   |      |         |   |      |   |         |      |  |   |         |   |  |      |          |   |  |   |          |   |  |   |         |  
|Future net cash flows   |  |                           | 228,863  |          |                           |   | 164,017 |             |   |   | 164,324 |          |   |      | 64,044  |   |      |   | 42,147  |      |  |   | 29,371  |   |  |      | 292,907  |   |  |   | 206,164  |   |  |   | 193,695 |  
|10% discount factor     |  |                           | (120,548 | )        |                           |   | (85,161 | )           |   |   | (86,131 | )        |   |      | (31,749 | ) |      |   | (20,412 | )    |  |   | (13,709 | ) |  |      | (152,297 | ) |  |   | (105,573 | ) |  |   | (99,840 | )
|                        |  |                           |          |          |                           |   |         |             |   |   |         |          |   |      |         |   |      |   |         |      |  |   |         |   |  |      |          |   |  |   |          |   |  |   |         |  
|Standardized measure    |  | $                         | 108,315  |          |                           | $ | 78,856  |             |   | $ | 78,193  |          |   | $    | 32,295  |   |      | $ | 21,735  |      |  | $ | 15,662  |   |  | $    | 140,610  |   |  | $ | 100,591  |   |  | $ | 93,855  |  
|                        |  |                           |          |          |                           |   |         |             |   |   |         |          |   |      |         |   |      |   |         |      |  |   |         |   |  |      |          |   |  |   |          |   |  |   |         |  
|                        |  |                           |          |          |                           |   |         |             |  
|Underlying Properties   |  |                           |          |          |                           |   |         |             |   |   |         |          |   |      |         |   |      |   |         |      |  |   |         |   |  |      |          |   |  |   |          |   |  |   |         |  
|                        |  |                           |         
|Future cash inflows     |  |                           | $        | 437,017  |                           |   | $       | 313,937     |   |   | $       | 287,484  |  
|Future production costs |  |                           |          | (97,333  | )                         |   |         | (75,500     | ) |   |         | (65,741  | )
|                        |  |                           |          |          |                           |   |         |             |   |   |         |          |  
|Future net cash flows   |  |                           |          | 339,684  |                           |   |         | 238,437     |   |   |         | 221,743  |  
|10% discount factor     |  |                           |          | (176,274 | )                         |   |         | (121,839    | ) |   |         | (113,979 | )
|                        |  |                           |          |          |                           |   |         |             |   |   |         |          |  
|Standardized measure    |  |                           | $        | 163,410  |                           |   | $       | 116,598     |   |   | $       | 107,764  |  
|                        |  |                           |          |          |                           |   |         |             |   |   |         |          |   |      |         |   |      |   |         |      |  |   |         |   |  |      |          |   |  |   |          |   |  |   |         |  



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



|                                                         |  |                           |         |         |                           |   |         |         |   |   |         |         |   |      |        |   |      |   |        |      |  |   |        |   |  |      |         |   |  |   |         |   |  |   |         |  
|-------------------------------------------------------- |  | ------------------------- | ------- | ------- | ------------------------- | - | ------- | ------- | - | - | ------- | ------- | - | ---- | ------ | - | ---- | - | ------ | ---- |  | - | ------ | - |  | ---- | ------- | - |  | - | ------- | - |  | - | ------- | -
|(in thousands)                                           |  | 90% Net Profits Interests |         |         | 75% Net Profits Interests |   |         | Total   |  
|                                                         |  | 2005                      |         |         | 2004                      |   |         | 2003    |   |   | 2005    |         |   | 2004 |        |   | 2003 |   |        | 2005 |  |   | 2004   |   |  | 2003 |        
|Net Profits Interests                                    |  |                           |         |         |                           |   |         |         |   |   |         |         |   |      |        |   |      |   |        |      |  |   |        |   |  |      |         |   |  |   |         |   |  |   |         |  
|                                                         |  |                           |         |         |                           |   |         |         |  
|Standardized measure, January 1                          |  | $                         | 78,856  |         |                           | $ | 78,193  |         |   | $ | 63,937  |         |   | $    | 21,735 |   |      | $ | 15,662 |      |  | $ | 16,054 |   |  | $    | 100,591 |   |  | $ | 93,855  |   |  | $ | 79,991  |  
|Extensions, additions and discoveries                    |  |                           | 2,647   |         |                           |   | 1,906   |         |   |   | 859     |         |   |      | -0-    |   |      |   | -0-    |      |  |   | -0-    |   |  |      | 2,647   |   |  |   | 1,906   |   |  |   | 859     |  
|Accretion of discount                                    |  |                           | 6,615   |         |                           |   | 6,578   |         |   |   | 5,367   |         |   |      | 1,909  |   |      |   | 1,398  |      |  |   | 1,428  |   |  |      | 8,524   |   |  |   | 7,976   |   |  |   | 6,795   |  
|Revisions of prior estimates, changes in price and other |  |                           | 35,649  |         |                           |   | 4,732   |         |   |   | 19,021  |         |   |      | 12,834 |   |      |   | 7,344  |      |  |   | 133    |   |  |      | 48,483  |   |  |   | 12,076  |   |  |   | 19,154  |  
|Net profits income                                       |  |                           | (15,452 | )       |                           |   | (12,553 | )       |   |   | (10,991 | )       |   |      | (4,183 | ) |      |   | (2,669 | )    |  |   | (1,953 | ) |  |      | (19,635 | ) |  |   | (15,222 | ) |  |   | (12,944 | )
|                                                         |  |                           |         |         |                           |   |         |         |   |   |         |         |   |      |        |   |      |   |        |      |  |   |        |   |  |      |         |   |  |   |         |   |  |   |         |  
|Standardized measure, December 31                        |  | $                         | 108,315 |         |                           | $ | 78,856  |         |   | $ | 78,193  |         |   | $    | 32,295 |   |      | $ | 21,735 |      |  | $ | 15,662 |   |  | $    | 140,610 |   |  | $ | 100,591 |   |  | $ | 93,855  |  
|                                                         |  |                           |         |         |                           |   |         |         |   |   |         |         |   |      |        |   |      |   |        |      |  |   |        |   |  |      |         |   |  |   |         |   |  |   |         |  
|                                                         |  |                           |         |         |                           |   |         |         |  
|Underlying Properties                                    |  |                           |         |         |                           |   |         |         |   |   |         |         |   |      |        |   |      |   |        |      |  |   |        |   |  |      |         |   |  |   |         |   |  |   |         |  
|                                                         |  |                           |        
|Standardized measure, January 1                          |  |                           | $       | 116,598 |                           |   | $       | 107,764 |   |   | $       | 92,447  |  
|Revisions:                                               |  |                           |         |         |                           |   |         |         |   |   |         |         |   |      |        |   |      |   |        |      |  |   |        |   |  |      |         |   |  |   |         |   |  |   |         |  
|Prices and costs                                         |  |                           |         | 57,635  |                           |   |         | 14,539  |   |   |         | 15,737  |  
|Quantity estimates                                       |  |                           |         | (266    | )                         |   |         | 882     |   |   |         | 5,717   |  
|Accretion of discount                                    |  |                           |         | 9,895   |                           |   |         | 9,149   |   |   |         | 7,867   |  
|Future development costs                                 |  |                           |         | (642    | )                         |   |         | (339    | ) |   |         | (148    | )
|Other                                                    |  |                           |         | (6      | )                         |   |         | (7      | ) |   |         | 7       |  
|                                                         |  |                           |         |         |                           |   |         |         |   |   |         |         |   |      |        |   |      |   |        |      |  |   |        |   |  |      |         |   |  |   |         |   |  |   |         |  
|Net revisions                                            |  |                           |         | 66,616  |                           |   |         | 24,224  |   |   |         | 29,180  |  
|Extensions, additions and discoveries                    |  |                           |         | 2,942   |                           |   |         | 2,117   |   |   |         | 954     |  
|Production                                               |  |                           |         | (23,388 | )                         |   |         | (17,846 | ) |   |         | (14,965 | )
|Development costs                                        |  |                           |         | 642     |                           |   |         | 339     |   |   |         | 148     |  
|                                                         |  |                           |         |         |                           |   |         |         |   |   |         |         |   |      |        |   |      |   |        |      |  |   |        |   |  |      |         |   |  |   |         |   |  |   |         |  
|Net change                                               |  |                           |         | 46,812  |                           |   |         | 8,834   |   |   |         | 15,317  |  
|                                                         |  |                           |         |         |                           |   |         |         |   |   |         |         |   |      |        |   |      |   |        |      |  |   |        |   |  |      |         |   |  |   |         |   |  |   |         |  
|Standardized measure, December 31                        |  |                           | $       | 163,410 |                           |   | $       | 116,598 |   |   | $       | 107,764 |  
|                                                         |  |                           |         |         |                           |   |         |         |   |   |         |         |   |      |        |   |      |   |        |      |  |   |        |   |  |      |         |   |  |   |         |   |  |   |         |  



11



---

Reversion Agreement



Certain of the properties underlying the 90% net profits interests are subject to a reversion agreement between XTO Energy and an unrelated third party.
The agreement calls for XTO Energy to transfer 25% of its interest in those properties to the third party when net amounts received by XTO Energy from the 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 net proceeds payable to the trust and trust distributions to unitholders would be
reduced. Based on 2005 prices and sales volumes, XTO Energy has informed the trustee that payout may occur within the next year, which would reduce monthly distributions by approximately 5%. Anticipated payout has recently been accelerated by higher
product prices and increased development of properties subject to the reversion agreement. Changes in product prices and sales volumes significantly affect when payout occurs.



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. Federal price controls on wellhead sales of domestic natural gas terminated on January 1, 1993. On August 8, 2005, Congress enacted the Energy Policy Act of 2005. The Energy
Policy Act, among other things, amended the Natural Gas Act to prohibit market manipulation by any entity, to direct FERC to facilitate market transparency in the market for sale or transportation of physical natural gas in interstate commerce, and
to significantly increase the penalties for violations of the Natural Gas Act, the Natural Gas Act of 1978, or FERC rules, regulations or orders thereunder. 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.



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
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.



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.



12



---

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 2005.



13



---

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, 2005 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
|                              |  | 2005                   |            | 2004 |   | 2003       |  | 2002 |            | 2001
|Net Profits Income            |  | $                      | 20,607,961 |      | $ | 15,222,417 |  | $    | 12,944,047 |      | $ | 9,049,271  |  | $ | 14,389,316
|Distributable Income          |  |                        | 20,267,436 |      |   | 14,924,058 |  |      | 12,688,746 |      |   | 8,822,310  |  |   | 14,209,884
|Distributable Income per Unit |  |                        | 3.377906   |      |   | 2.487343   |  |      | 2.114791   |      |   | 1.470385   |  |   | 2.368314  
|Distributions per Unit        |  |                        | 3.377906   |      |   | 2.487343   |  |      | 2.114791   |      |   | 1.470385   |  |   | 2.368314  
|Total Assets at Year-End      |  |                        | 23,318,733 |      |   | 24,284,184 |  |      | 25,660,147 |      |   | 27,805,823 |  |   | 29,747,914



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 each of the years in the three-year period
ended December 31, 2005 in the trusts annual report to unitholders for the year ended December 31, 2005 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 underlying properties. 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,
2005, other than the December distribution payable to unitholders in January 2006, 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 |  | $                      | 2,114,010 |                  | $ | 2,114,010 |  | $         |  |                  | $ |  |  | $ | 



14



---

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, 2005, this monthly charge was $24,080 ($18,060 net to the trust). XTO Energy also deducts an overhead charge as operator of the Penwell
Unit. As of December 31, 2005, monthly overhead attributable to the Penwell Unit was $2,392 ($1,794 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, 2005.



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 U.S. 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 U.S.
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 U.S. 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, 2005.



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.



15



---

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 explained in Item 1A.



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 16, 2006, appearing in the trusts annual report to unitholders for the year ended December 31, 2005, are incorporated herein by reference.



16



---

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, 2005.



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 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, 2005. The
trustees assessment of the effectiveness of the trusts internal control over financial reporting as of December 31, 2005 has been audited by KPMG LLP, an independent registered public accounting firm, as stated in their report which
is included herein.



There were no changes in the trusts
internal control over financial reporting during the quarter ended December 31, 2005 that have materially affected, or are reasonably likely to materially affect, the trusts internal control over financial reporting.



Item 9B.Other Information



None.



17



---

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, 2005.



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 2003 through
2005 as specified in the trust indenture:



|                               |  |      |  |                              |       
|------------------------------ |  | ---- |  | ---------------------------- | ------
|Name and Principal Position    |  | Year |  | Other AnnualCompensation (1)
|Bank of America, N.A., Trustee |  | 2005 |  | $                            | 10,304
|                               |  | 2004 |  |                              | 7,611 
|                               |  | 2003 |  |                              | 6,472 

---

|(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 February 16, 2006, Bank
of America, N.A. owned, in various fiduciary capacities, 56,322 units with a shared right to vote 27,138 of these units and no right to vote 29,184 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.



18



---

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, 2005 was $24,080 per month, or $288,960 annually (net to the trust of $216,720 annually). XTO
Energy also deducts an overhead charge as operator of the Penwell Unit. As of December 31, 2005, overhead attributable to the Penwell Unit was $2,392 per month, or $28,704 annually (net to the trust of $21,528 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 2003 through 2005 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, 2005 and 2004 are:



|                   |  |      |        |      |   |       
|------------------ |  | ---- | ------ | ---- | - | ------
|                   |  | 2005 |        | 2004
|Audit fees         |  | $    | 66,000 |      | $ | 76,206
|Audit-related fees |  |      |       |      |   |      
|Tax fees           |  |      |       |      |   |      
|All other fees     |  |      |       |      |   |      
|                   |  |      |        |      |   |       
|                   |  | $    | 66,000 |      | $ | 76,206
|                   |  |      |        |      |   |       



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.



19



---

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, 2005 and 2004

Statements of Distributable Income for the years ended December 31, 2005, 2004 and 2003

Statements of Changes in Trust Corpus for the years ended December 31, 2005, 2004 and 2003

Notes to Financial Statements



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



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



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



|        |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                       
|------- |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|        | 
|(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) 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) 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) 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, 2005                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                         



20



---

|       |  |                                       
|------ |  | --------------------------------------
|       | 
|(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.



21



---

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 16, 2006 |  |  |  | By              |  | /s/ LOUIS G. BALDWIN
|                     |  |  |  |                 |  |                      |  | Louis G. Baldwin Executive Vice President and Chief Financial Officer



(The trust has no
directors or executive officers.)



22