10-K

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

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overpayment, but net profits income payable to the trust for the next month will be reduced by the overpayment, plus interest at the prime rate.

Approximately 20 of the underlying royalty interests in the San Juan Basin burden working interests in properties operated by XTO Energy. 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.

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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

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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

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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.

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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

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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.

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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

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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 Profits Interests				75% Net Profits Interests				Total				Underlying Properties
	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		Underlying Properties
	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 than 5 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, 17^th Floor, 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 Annual Compensation (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.)

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EX-13

Exhibit 13

CROSS TIMBERS ROYALTY TRUST

GLOSSARY OF TERMS

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

Bbl	Barrel (of oil)
Bcf	Billion cubic feet (of natural gas)
Mcf	Thousand cubic feet (of natural gas)
MMBtu	One million British Thermal Units, a common energy measurement
net proceeds	Gross proceeds received by XTO Energy from sale of production from the underlying properties, less applicable costs, as defined in the net profits interest conveyances
net profits income	Net proceeds multiplied by the applicable net profits percentage of 75% or 90%, which is paid to the trust by XTO Energy. “Net profits income” is referred to as “royalty income” for income tax purposes.
net profits interest	An interest in an oil and gas property measured by net profits from the sale of production, rather than a specific portion of production. The following defined net profits interests were conveyed to the trust from the underlying properties:
	90% net profits interests – interests that entitle the trust to receive 90% of the net proceeds from the underlying properties that are royalty or overriding royalty interests in Texas, Oklahoma and New Mexico
	75% net profits interests – interests that entitle the trust to receive 75% of the net proceeds from the underlying properties that are working interests in Texas and Oklahoma
royalty interest (and overriding royalty interest)	A nonoperating interest in an oil and gas property that provides the owner a specified share of production without any production expense or development costs
underlying properties	XTO Energy’s interest in certain oil and gas properties from which the net profits interests were conveyed. The underlying properties include royalty and overriding royalty interests in producing and nonproducing properties in Texas, Oklahoma and New Mexico, and working interests in producing properties located in Texas and Oklahoma.
working interest	An operating interest in an oil and gas property that provides the owner a specified share of production that is subject to all production expense and development costs

THE TRUST

Cross Timbers Royalty Trust was created on February 12, 1991 by conveyance of 90% net profits interests in certain royalty and overriding royalty interest properties in Texas, Oklahoma and New Mexico, and 75% net profits interests in certain working interest properties in Texas and Oklahoma. XTO Energy Inc. owns the underlying properties from which these net profits interests were conveyed. The net profits interests are the only assets of the trust, other than cash held for trust expenses and for distribution to unitholders.

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

UNITS OF BENEFICIAL INTEREST

The units of beneficial interest in the trust are listed and traded on the New York Stock Exchange under the symbol “CRT.” The following are the high and low unit sales prices and total cash distributions per unit paid by the trust during each quarter of 2005 and 2004:

	Sales Price				Distributions per Unit
Quarter	High		Low
2005
First	$	45.95	$	35.26	$	0.723424
Second		42.35		36.05		0.742308
Third		56.34		38.55		0.839848
Fourth		59.00		45.75		1.072326
					$	3.377906
2004
First	$	28.85	$	24.50	$	0.507664
Second		30.23		26.25		0.592632
Third		33.33		27.74		0.654790
Fourth		41.75		32.82		0.732257
					$	2.487343

At December 31, 2005, there were 6,000,000 units outstanding and approximately 439 unitholders of record; 5,747,772 of these units were held by depository institutions. In September 2003, XTO Energy distributed all of the 1,360,000 units it owned as a dividend to its common stockholders. XTO Energy currently is not a unitholder of the trust.

Forward-Looking Statements

This Annual Report, including the accompanying Form 10-K, includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements other than statements of historical fact included in this Annual Report and Form 10-K, including, without limitation, statements regarding estimates of proved reserves, future development plans and costs, and industry and market conditions, are forward-looking statements that are subject to a number of risks and uncertainties which are detailed in Part I, Item 1A of the accompanying Form 10-K. Although XTO Energy and the trustee believe that the expectations reflected in such forward-looking statements are reasonable, neither XTO Energy nor the trustee can give any assurance that such expectations will prove to be correct.

SUMMARY

The trust was created to collect and distribute monthly net profits income to unitholders. Trust net profits income is received from two major components, the 90% net profits interests and the 75% net profits interests.

— The 90% net profits interests were conveyed from underlying royalty and overriding royalty interests in producing properties in Texas, Oklahoma and New Mexico. Most net profits income is from long-lived gas properties in the San Juan Basin of northwestern New Mexico. Because the 90% net profits interests are not subject to production expense or development costs, net profits income from these interests generally only varies because of changes in sales volumes or prices.

— The 75% net profits interests were conveyed from underlying working interests in seven large, predominantly oil-producing properties in Texas and Oklahoma. Net profits income from these properties is reduced by production expense and development costs. If costs exceed revenues from the underlying working interest properties in either Texas or Oklahoma, the 75% net profits interests for that state will not contribute to trust net profits income until all excess costs and accrued interest have been recovered from future net proceeds of that state. However, such excess costs will not reduce net profits income from the other 75% net profits interests or from the 90% net profits interests. Such excess costs generally occur during periods of higher development activity and/or lower oil prices.

The following table summarizes the effect of the above components on distributions per unit for the last three years:

	2005						2004						2003
	Monthly Average			Annual Total			Monthly Average			Annual Total			Monthly Average			Annual Total
Net profits income:
— 90% net profits interests	$	0.228	(a)	$	2.738	(a)	$	0.174		$	2.092		$	0.153		$	1.832
— 75% net profits interests		0.058			0.697			0.037			0.445			0.027			0.326
Administration expense (net of interest income)		(0.005	)		(0.057	)		(0.004	)		(0.050	)		(0.004	)		(0.043	)
Total Distribution	$	0.281		$	3.378		$	0.207		$	2.487		$	0.176		$	2.115

(a) Includes a one-time payment from a purchaser for prior period revenues of $675,210 and related interest of $973,060, or a total of $1,648,270, or $0.275 per unit (a monthly average of $0.023 per unit).

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

As an example, a unitholder that acquired units in January 2005 and held them throughout 2005 would be entitled to a cost depletion deduction of approximately 8% of his cost. Assuming a cost of $39.00 per unit, cost depletion would offset approximately 87% of 2005 taxable trust income. Assuming a 30% tax rate, the 2005 taxable equivalent return as a percentage of unit cost would be 12%. (NOTE- Because the units are a depleting asset, a portion of this return is effectively a return of capital.)

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. Under the terms of this agreement, net proceeds payable to the trust and monthly trust distributions to unitholders may be reduced within the next year by approximately 5%, based on 2005 sales volumes and average prices. See “Trustee’s Discussion and Analysis—Years Ended December 31, 2005, 2004 and 2003—Reversion Agreement.”

TO UNITHOLDERS

We are pleased to present the 2005 Annual Report of Cross Timbers Royalty Trust. This report includes a copy of the trust’s 2005 Form 10-K as filed with the Securities and Exchange Commission. Both reports contain important information about the trust’s net profits interests, including information provided to the trustee by XTO Energy, and should be read in conjunction with each other.

For the year ended December 31, 2005, net profits income totaled $20,607,961. After deducting trust administration expense and adding interest income, distributable income was $20,267,436, or $3.377906 per unit. Distributions for the year were higher than in 2004 primarily because of higher oil and gas prices.

Natural gas prices for 2005 averaged $7.76 per Mcf for sales from the underlying properties, a 35% increase from the 2004 average price of $5.73 per Mcf. Gas sales volumes from the underlying properties for the year ended December 31, 2005 totaled 2,252,361 Mcf, or 6,171 Mcf per day, a 13% decrease from 2004 production of 2,584,814 Mcf, or 7,062 Mcf per day. Gas sales volumes were lower primarily because of natural production decline, as well as the timing of cash receipts and prior period volume adjustments.

The average oil price increased to $49.70 per Bbl, up 39% from the 2004 average price of $35.68 per Bbl. Oil sales volumes from the underlying properties during 2005 were 270,525 Bbls, or 741 Bbls per day, a 2% decrease from 2004 levels of 275,792 Bbls, or 754 Bbls per day. Oil sales volumes were lower primarily because of natural production decline, partially offset by the timing of cash receipts.

As of December 31, 2005, proved reserves for the underlying properties were estimated by independent engineers to be 3.3 million Bbls of oil and 32.9 Bcf of natural gas. Based on an allocation of these reserves, proved reserves attributable to the net profits interests were estimated to be 1.7 million Bbls of oil and 29.1 Bcf of natural gas. Proved reserves for the underlying properties and attributable to the net profits interests as of December 31, 2005, 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 an unrelated third party when payout occurs. 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%. See “Trustee’s Discussion and Analysis—Years Ended December 31, 2005, 2004 and 2003—Reversion Agreement.”

From year-end 2004 to 2005, oil reserves for the underlying properties decreased approximately 5%, while oil reserves attributable to the net profits interests were unchanged, primarily because of the effects of the reversion agreement and production, offset by increased reserves related to higher year-end oil prices. Year-end gas reserves for the underlying properties, as well as for the net profits interests, decreased approximately 4% from 2004 to 2005 primarily because of the effects of the reversion agreement and production, partially offset by reserve additions from development activity in the San Juan Basin. All reserve information prepared by independent engineers has been provided to the trustee by XTO Energy.

Estimated future net cash flows from proved reserves of the net profits interests at December 31, 2005 are $292.9 million, or $48.82 per unit. Using an annual discount factor of 10%, the present value of estimated future net cash flows at December 31, 2005 is $140.6 million, or $23.44 per unit. Proved reserve estimates and related future net cash flows have been determined based on a year-end West Texas Intermediate posted oil price of $57.75 per Bbl and a year-end average realized gas price of $7.70 per Mcf. Other guidelines used in estimating proved reserves, as prescribed by the Financial Accounting Standards Board, are described under Item 2 of the accompanying Form 10-K. The present value of estimated future net cash flows is not indicative of the market value of trust units.

As disclosed in the tax instructions provided to unitholders in February 2006, trust distributions are considered portfolio income, rather than passive income. Unitholders should consult their tax advisors for further information.

Cross Timbers Royalty Trust

By: Bank of America, N.A., Trustee

By: Nancy G. Willis

Vice President

THE UNDERLYING PROPERTIES

The underlying properties include over 2,900 producing properties with established production histories in Texas, Oklahoma and New Mexico. The average reserve-to-production index for the underlying properties as of December 31, 2005 is approximately 13 years. This index is calculated using total proved reserves and estimated 2006 production for the underlying properties. The projected 2006 production is from proved developed producing reserves as of December 31, 2005. Based on estimated future net cash flows at year-end oil and gas prices, the proved reserves of the underlying properties are approximately 31% oil and 69% natural gas. The underlying properties also include certain nonproducing properties in Texas, Oklahoma and New Mexico that are primarily mineral interests. As discussed below under “75% Net Profits Interests,” XTO Energy became operator of the Penwell Unit in August 2004. Other than this property and approximately 20 of the underlying royalty interests in the San Juan Basin that burden operated working interests, XTO Energy cannot significantly influence or control the operations of the underlying properties.

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.

90% Net Profits Interests

Royalty and overriding royalty properties underlying the 90% net profits interests represent 77% of the discounted future net cash flows from trust proved reserves at December 31, 2005. Approximately 89% of the discounted future net cash flows from the 90% net profits interests is from gas reserves, totaling 28.6 Bcf. Oil reserves underlying the 90% net profits interests are primarily located in West Texas and are estimated to be 501,000 Bbls at December 31, 2005.

Because the properties underlying the 90% net profits interests are royalty interests and overriding royalty interests, net profits income from these properties is not reduced by production expense or development costs. Additionally, net profits income from these interests cannot be reduced by any excess costs of the 75% net profits interests. The trust, therefore, should generally receive monthly net profits income from these interests, as determined by oil and gas sales volumes and prices.

Most of the trust’s gas reserves are located in the San Juan Basin of northwestern New Mexico, one of the largest domestic gas fields. The San Juan Basin royalties produced approximately 77% of the trust’s gas sales volumes and accounted for 52% of the net profits income for 2005. As of December 31, 2005, trust proved gas reserves in this region are estimated to be 23.7 Bcf, or 81% of total trust gas reserves.

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 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 potential effect on the trust is unknown.

Most of the trust’s San Juan Basin conventional, or non-coal seam, gas is produced 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.

75% Net Profits Interests

Underlying the 75% net profits interests are working interests in seven large, predominantly oil-producing properties in Texas and Oklahoma operated primarily by established oil companies. These properties are located in mature fields undergoing secondary or tertiary recovery operations. Most of the oil produced from the 75% net profits interest properties is sour oil, which is sold at a wider decrement to NYMEX sweet crude oil prices. As a result of an acquisition in August 2004, XTO Energy became operator of the Penwell Unit. XTO Energy’s original interest in this unit is one of the properties underlying the Texas 75% net profits interests. With the exception of the Penwell Unit, XTO Energy generally has little influence or control over operations on any of these properties.

Proved reserves from the 75% net profits interests are almost entirely oil, estimated to be approximately 1.2 million Bbls at year-end 2005. Based on year-end oil and gas prices, proved reserves from these interests represent 23% of the discounted future net cash flows of the trust’s proved reserves at December 31, 2005.

Because these underlying properties are working interests, production expense and development costs are deducted in calculating net profits income from the 75% net profits interests. As a result, net profits income from these interests is affected by the level of maintenance and development activity on these underlying properties. Net profits income is also dependent upon oil and gas sales volumes and prices and is subject to reduction for any prior period excess costs.

Total 2005 development costs were $641,657, up 89% from 2004 development costs of $338,812. Development costs were higher in 2005 because of increased development activity and higher costs. January and February 2006 development costs totaled approximately $207,000, and were primarily incurred in fourth quarter 2005.

As reported to XTO Energy by unit operators in February of each year, budgeted development costs were $272,000 for 2005 and $777,000 for 2004. Actual development costs often differ from amounts budgeted because of changes in product prices and other factors that may affect the timing or selection of projects. Also, costs are deducted in the calculation of trust net profits income several months after they are incurred by the operator. Unit operators have reported total budgeted costs, net to the underlying properties, of approximately $1.8 million annually for 2006 and 2007.

There were no excess costs in 2003, 2004 or 2005. For information regarding the effect of excess costs on trust net profits income, see “Trustee’s Discussion and Analysis—Years Ended December 31, 2005, 2004 and 2003—Costs.”

Estimated Proved Reserves and Future Net Cash Flows

The following are proved reserves of the underlying properties, as estimated by independent engineers, and proved reserves and future net cash flows from proved reserves of the net profits interests, based on an allocation of these reserves, at December 31, 2005:

	Underlying Properties		Net Profits Interests
	Proved Reserves (a)		Proved Reserves (a) (b)		Future Net Cash Flows from Proved Reserves (a) (c)
(in thousands)	Oil (Bbls)	Gas (Mcf)	Oil (Bbls)	Gas (Mcf)	Undiscounted		Discounted
90% Net Profits Interests
San Juan Basin	46	26,320	41	23,688	$	163,222	$	75,202
Other New Mexico	51	189	46	163		4,146		2,248
Texas	408	3,085	367	2,775		42,244		21,303
Oklahoma	52	2,206	47	1,942		19,251		9,562
Total	557	31,800	501	28,568		228,863		108,315
75% Net Profits Interests
Texas	1,293	742	592	340		32,263		15,535
Oklahoma	1,449	400	598	165		31,781		16,760
Total	2,742	1,142	1,190	505		64,044		32,295
TOTAL	3,299	32,942	1,691	29,073	$	292,907	$	140,610

(a) Based on year-end oil and gas prices. Discounted estimated future net cash flows from proved reserves increased 40% from year-end 2004 to 2005, primarily because of a 50% increase in year-end natural gas prices and a 43% increase in year-end oil prices over these periods. For further information regarding proved reserves and the method of allocation of proved reserves to the net profits interests, see Item 2 of the accompanying Form 10-K.

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

(c) Before income taxes since future net cash flows are not subject to taxation at the trust level.

TRUSTEE’S DISCUSSION AND ANALYSIS

Years Ended December 31, 2005, 2004 and 2003

Net profits income for 2005 was $20,607,961, as compared with $15,222,417 for 2004 and $12,944,047 for 2003. The 35% increase in net profits income from 2004 to 2005 and the 18% increase in net profits income from 2003 to 2004 was primarily because of increased oil and gas prices. During 2005, 2004 and 2003, 65%, 69% and 73%, respectively, of net profits income was derived from gas sales.

Trust administration expense was $363,582 in 2005 as compared to $304,390 in 2004 and $259,811 in 2003. Increased administration expense from 2004 to 2005 is primarily because of the timing of expenditures related to the audit of the trust’s internal control over financial reporting. Administration expense increased from 2003 to 2004 primarily because of increased unitholder reporting expenses related to an increased number of unitholders and the timing of expenditures. Interest income was $23,057 in 2005, $6,031 in 2004 and $4,510 in 2003. Changes in interest income are attributable to fluctuations in net profits income and interest rates.

Net profits income is recorded when received by the trust, which is the month following receipt by XTO Energy, and generally two months after oil production and three months after gas production. Net profits income is generally affected by three major factors:

• oil and gas sales volumes,

• oil and gas sales prices, and

• costs deducted in the calculation of net profits income.

Volumes

Oil. Underlying oil sales volumes decreased 2% from 2004 to 2005, as compared to an 8% decrease from 2003 to 2004. Decreased oil sales volumes in 2005 were primarily because of natural production decline, partially offset by the timing of cash receipts. Decreased oil sales volumes in 2004 were primarily because of natural production decline, partially offset by the effect of prior period volume adjustments in 2003.

Gas. Underlying gas sales volumes decreased 13% from 2004 to 2005 as compared to a 3% decrease from 2003 to 2004. Decreased gas sales volumes in 2005 were primarily because of natural production decline, as well as the timing of cash receipts and prior period volume adjustments. Decreased gas sales volumes in 2004 were primarily because of the timing of cash receipts and natural production decline, partially offset by prior period volume adjustments in 2003.

Prices

Oil. The average oil price for 2005 was $49.70 per Bbl, 39% higher than the 2004 average oil price of $35.68, which was 27% higher than the 2003 average price of $28.04. Since late 2002, oil prices have generally been rising primarily because of increasing global demand and supply shortage concerns, inadequate refining capacity, reduced production as a result of tropical storms and hurricanes in the Gulf of Mexico and political instability. Oil prices increased to record levels in August 2005, exceeding $70.00 per Bbl. Oil prices are expected to remain volatile. The average NYMEX price for January and February 2006 was $63.67, compared with $56.57 for the year 2005 and $60.00 for fourth quarter 2005. Recent trust oil prices have averaged approximately $5.05, or 8%, lower than the NYMEX price.

Gas. The 2005 average gas price was $7.76 per Mcf, a 35% increase from the 2004 average gas price of $5.73, which was 18% higher than the 2003 average price of $4.86. Since late 2002, gas prices have generally been increasing due primarily to increased demand and declining North American production. These trends accelerated in the second half of 2005 due to the effects of hurricanes on Gulf of Mexico production. During the last half of 2005 and the first two months of 2006, gas prices have ranged from a high in excess of $15.00 per MMBtu to a low of almost $6.50 per MMBtu. Prices will continue to be affected by weather, the U.S. economy, the level of North American production, crude oil prices and import levels of liquified natural gas. In any case, natural gas prices are expected to remain volatile.

For the past two years, trust average gas prices have generally approximated or been slightly higher than NYMEX prices for the related production period. However, beginning with trust distributions declared in December 2005 and paid in January 2006, the trust average price has been significantly lower than the related NYMEX price. NYMEX prices are generally representative of the price received for gas delivered in the Louisiana Gulf coast region, where demand is higher and supply has been diminished since August 2005 because of the Gulf hurricanes, causing NYMEX prices to significantly increase. Because of greater supply and weaker demand in the regions where gas from the underlying properties is delivered and sold, trust gas prices have not risen as dramatically as NYMEX prices. This has resulted in a widening decrement between the NYMEX and trust average gas prices. The average NYMEX price for fourth quarter 2005 was $12.80 per MMBtu. The related trust gas prices for distributions declared in first quarter 2006 have been approximately 27% lower than the NYMEX price. The average NYMEX price for January and February 2006, which primarily relates to trust distributions declared in second quarter 2006, was $8.37 per MMBtu.

See “Gulf of Mexico Hurricanes” below.

Costs

Because properties underlying the 90% net profits interests are royalty and overriding royalty interests, the calculation of net profits income from these interests only includes deductions for production and property taxes, legal costs, and marketing and transportation charges. In addition to these costs, the calculation of net profits income from the 75% net profits interests includes deductions for production expense and development costs since the related underlying properties are working interests. Net profits income is calculated monthly for each of the five conveyances under which the net profits interests were conveyed to the trust. If monthly costs exceed revenues for any conveyance, such excess costs must be recovered, with accrued interest, from future net proceeds of that conveyance and cannot reduce net profits income from other conveyances. Costs have never exceeded revenues from 90% net profits interests, nor are they expected to in the future. The last time one of the 75% net profits interests conveyances were in an excess cost position was in March 2002; these excess costs and related accrued interest were fully recovered by May 2002.

Total costs deducted in the calculation of net profits income were $8.2 million in 2005, $7.2 million in 2004 and $6.6 million in 2003. The 14% increase in costs from 2004 to 2005 is attributable to higher production taxes associated with increased revenues, increased production expense related to the timing of maintenance projects and higher development costs. The 9% increase in costs from 2003 to 2004 is primarily attributable to higher production taxes associated with increased revenues and higher development costs, partially offset by decreased production expense related to the timing of maintenance projects.

Unit operators of the properties underlying the 75% net profits interests have reported total budgeted development costs, net to the underlying properties, of approximately $1.8 million annually for 2006 and 2007, as compared to budgeted development costs of $272,000 and actual development costs of $641,657 for 2005. Actual development costs often differ from amounts budgeted because of changes in product prices and other factors that may affect the timing or selection of projects.

Other Proceeds

The calculation of net profits income for 2005 includes interest income of $1,081,178 related to a purchaser’s recalculation and remittance of royalties of $750,233 for prior period San Juan Basin production. This total one-time adjustment, net to the trust, was $1,648,270, or approximately $0.28 per unit.

Gulf of Mexico Hurricanes

In late August and September 2005, hurricanes in the Gulf of Mexico disrupted a significant portion of U.S. oil and gas production, leading to higher and more volatile commodity prices. These increased prices began affecting distributions to unitholders beginning with the December 2005 distribution that was paid in January 2006. The underlying properties to the trust are not located near the Gulf and related production was not significantly affected. However, because of greater supply and weaker demand in areas where trust related oil and gas is produced, the price received for such production has been significantly lower than the price received for Gulf production or NYMEX prices. Production expense and development costs have increased throughout the industry because of storm damages and related supply shortages.

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, 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.

Fourth Quarter 2005 and 2004

During the quarter ended December 31, 2005, the trust received net profits income totaling $6,487,591, compared with fourth quarter 2004 net profits income of $4,430,024. The 46% increase in net profits income from fourth quarter 2004 to 2005 was because of higher oil and gas prices, as well as interest income related to a purchaser’s remittance of prior period royalties.

Administration expense was $63,293 and trust interest income was $9,658, resulting in fourth quarter 2005 distributable income of $6,433,956, or $1.072326 per unit. Distributable income for fourth quarter 2004 was $4,393,542, or $0.732257 per unit. Distributions to unitholders for the quarter ended December 31, 2005 were:

Record Date	Payment Date	Per Unit
October 31, 2005	November 15, 2005	$0.435017
November 30, 2005	December 14, 2005	0.284974
December 30, 2005	January 17, 2006	0.352335
		$1.072326

Volumes

Fourth quarter 2005 underlying oil sales volumes were 67,196 Bbls, or 1% lower than 2004 levels. Oil sales volumes decreased in 2005 because of natural production decline, partially offset by the timing of cash receipts. Underlying gas sales volumes were 567,540 Mcf, or 13% lower than 2004 levels. This decrease in gas sales volumes was primarily because of natural production decline and the timing of cash receipts.

Prices

The average fourth quarter 2005 oil price was $59.05 per Bbl, 35% higher than the fourth quarter 2004 average price of $43.68. The average fourth quarter 2005 gas price was $8.50 per Mcf, 38% higher than the fourth quarter 2004 average price of $6.15. For further information about oil and gas prices, see “Years Ended December 31, 2005, 2004 and 2003 – Prices” above.

Costs

Costs deducted in the calculation of fourth quarter 2005 net profits income increased $577,273, or 31%, from fourth quarter 2004. This increase was primarily the result of increased development activity and increased production expense related to the timing of maintenance projects. For further information about costs, see “Years Ended December 31, 2005, 2004 and 2003—Costs” above.

Other Proceeds

The fourth quarter 2005 calculation of net profits income includes interest income of $1,081,178 related to a purchaser’s remittance of prior period royalties. See “Years Ended December 31, 2005, 2004 and 2003—Other Proceeds” above.

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

Calculation of Net Profits Income

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

	Year Ended December 31 (a)						Three Months Ended December 31 (a)
	2005		2004		2003		2005		2004
Sales Volumes
Oil (Bbls) (b)
Underlying properties		270,525		275,792		298,869		67,196		68,141
Average per day		741		754		819		730		741
Net profits interests		145,698		136,608		130,517		35,441		38,522
Gas (Mcf) (b)
Underlying properties		2,252,361		2,584,814		2,677,460		567,540		651,276
Average per day		6,171		7,062		7,336		6,169		7,079
Net profits interests		1,965,576		2,272,853		2,337,530		495,465		570,854
Average Sales Price
Oil (per Bbl)	$	49.70	$	35.68	$	28.04	$	59.05	$	43.68
Gas (per Mcf)	$	7.76	$	5.73	$	4.86	$	8.50	$	6.15
Revenues
Oil sales	$	13,444,407	$	9,839,883	$	8,381,516	$	3,967,979	$	2,976,382
Gas sales		17,471,247		14,823,564		13,020,253		4,822,822		4,005,420
Total Revenues		30,915,654		24,663,447		21,401,769		8,790,801		6,981,802
Costs
Taxes, transportation and other		4,005,653		3,693,129		3,078,195		1,132,275		1,040,195
Production expense (c)		3,522,305		3,124,582		3,358,846		962,863		751,573
Development costs		641,657		338,812		148,293		329,764		55,861
Total Costs		8,169,615		7,156,523		6,585,334		2,424,902		1,847,629
Other Proceeds
Interest income (d)		1,081,178		—		—		1,081,178		—
Net Proceeds	$	23,827,217	$	17,506,924	$	14,816,435	$	7,447,077	$	5,134,173
Net Profits Income	$	20,607,961	$	15,222,417	$	12,944,047	$	6,487,591	$	4,430,024

(a) Because of the interval between time of production and receipt of net profits income by the trust, oil and gas sales for the year ended December 31 generally relate to oil production from November through October and gas production from October through September, while oil and gas sales for the three months ended December 31 generally relate to oil production from August through October and gas production from July through September.

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

(c) Includes an overhead charge which is deducted and retained by XTO Energy. As of December 31, 2005, this charge was $26,472 per month (including a monthly overhead charge of $2,392 which XTO Energy deducts as operator of the Penwell Unit) and is subject to adjustment each May based on an oil and gas industry index.

(d) Interest income was received from a purchaser, related to the purchaser’s recalculation and remittance of royalties of $750,233 for prior period San Juan Basin production. The total one-time adjustment, net to trust, was $1,648,270, or approximately $0.28 per unit.

Cross Timbers Royalty Trust

STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS

	December 31
	2005		2004
Assets
Cash and short-term investments	$	2,111,521	$	1,435,478
Interest to be received		2,489		1,012
Net profits interests in oil and gas properties—net (Notes 1 and 2)		21,204,723		22,847,694
	$	23,318,733	$	24,284,184
Liabilities and Trust Corpus
Distribution payable to unitholders	$	2,114,010	$	1,436,490
Trust corpus (6,000,000 units of beneficial interest authorized and outstanding)		21,204,723		22,847,694
	$	23,318,733	$	24,284,184

STATEMENTS OF DISTRIBUTABLE INCOME

	Year Ended December 31
	2005		2004		2003
Net profits income	$	20,607,961	$	15,222,417	$	12,944,047
Interest income		23,057		6,031		4,510
Total income		20,631,018		15,228,448		12,948,557
Administration expense		363,582		304,390		259,811
Distributable income	$	20,267,436	$	14,924,058	$	12,688,746
Distributable income per unit (6,000,000 units)	$	3.377906	$	2.487343	$	2.114791

See Accompanying Notes to Financial Statements.

Cross Timbers Royalty Trust

STATEMENTS OF CHANGES IN TRUST CORPUS

	Year Ended December 31
	2005			2004			2003
Trust corpus, beginning of year	$	22,847,694		$	24,665,401		$	26,556,533
Amortization of net profits interests		(1,642,971	)		(1,817,707	)		(1,891,132	)
Distributable income		20,267,436			14,924,058			12,688,746
Distributions declared		(20,267,436	)		(14,924,058	)		(12,688,746	)
Trust corpus, end of year	$	21,204,723		$	22,847,694		$	24,665,401

See Accompanying Notes to Financial Statements.

Cross Timbers Royalty Trust

NOTES TO FINANCIAL STATEMENTS

1. Trust Organization and Provisions

Cross Timbers Royalty Trust was created on February 12, 1991 by predecessors of XTO Energy Inc., when the following net profits interests were conveyed under five separate conveyances to the trust effective October 1, 1990, in exchange for 6,000,000 units of beneficial interest in the trust:

— 90% net profits interests in certain producing and nonproducing royalty and overriding royalty interest properties in Texas, Oklahoma and New Mexico, and

— 75% net profits interests in certain nonoperated working interest properties in Texas and Oklahoma.

The underlying properties from which the net profits interests were carved are currently owned by XTO Energy. See Note 5.

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

— the trust may not engage in any business activity or acquire any assets other than the net profits interests and specific short-term cash investments;

— the trust may not dispose of all or part of the net profits interests unless approved by 80% of the unitholders, or upon trust termination, and any sale must be for cash with the proceeds promptly distributed to the unitholders;

— the trustee may establish a cash reserve for payment of any liability that is contingent or not currently payable;

— the trustee may borrow funds required to pay trust liabilities if fully repaid prior to further distributions to unitholders;

— the trustee will make monthly cash distributions to unitholders (Note 3); and

— the trust will terminate upon the first occurrence of:

— disposition of all net profits interests pursuant to terms of the trust indenture,

— gross revenue of the trust is less than $1 million per year for two successive years, or

— a vote of 80% of the unitholders to terminate the trust in accordance with provisions of the trust indenture.

2. Basis of Accounting

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

— Net profits income is recorded in the month received by the trustee (Note 3).

— Interest income, interest to be received and distribution payable to unitholders include interest to be earned on net profits income from the monthly record date (last business day of the month) through the date of the next distribution.

— Trust expenses are recorded based on liabilities paid and cash reserves established by the trustee for liabilities and contingencies.

— Distributions to unitholders are recorded when declared by the trustee (Note 3).

The most significant differences between the trust’s financial statements and those prepared in accordance with 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.

Most accounting pronouncements apply to entities whose financial statements are prepared in accordance with U.S. generally accepted accounting principles, directing such entities to accrue or defer revenues and expenses in a period other than when such revenues were received or expenses were paid. Because the trust’s financial statements are prepared on the modified cash basis, as described above, most accounting pronouncements are not applicable to the trust’s financial statements.

The initial carrying value of the net profits interests of $61,100,449 was XTO Energy’s historical net book value of the interests on February 12, 1991, the date of the transfer to the trust. Amortization of the net profits interests is calculated on a unit-of-production basis and charged directly to trust corpus. Accumulated amortization was $39,895,726 as of December 31, 2005 and $38,252,755 as of December 31, 2004.

3. Distributions to Unitholders

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

Net profits income received by the trustee consists of net proceeds received in the prior month by XTO Energy from the underlying properties multiplied by the net profits percentage of 90% or 75%. Net proceeds are the gross proceeds received from the sale of production, less applicable costs. For the 90% net profits interests, such costs generally include production and property taxes, legal costs, and marketing and transportation charges. In addition to these costs, the 75% net profits interests include deductions for production expense and development costs.

XTO Energy, as owner of the underlying properties, computes net profits income separately for each of the five conveyances (Note 1). If costs exceed gross proceeds for any conveyance, such excess costs cannot be used to reduce the amounts to be received under the other conveyances. The trust is

not liable for excess costs; however, such excess costs plus accrued interest are deducted in calculating future net profits income from that conveyance.

4. Federal Income Taxes

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

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

5. XTO Energy Inc.

The underlying properties include approximately 20 overriding royalty interests in New Mexico that burden working interests owned and operated by XTO Energy. These working interests were purchased by XTO Energy after the net profits interests were conveyed to the trust. XTO Energy also operates the Penwell Unit, following the 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.

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.

In computing net profits income for the 75% net profits interests (Note 3), 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 an annual adjustment based on an oil and gas industry index.

6. Contingencies

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.

7. Supplemental Oil and Gas Reserve Information (Unaudited)

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

8. Quarterly Financial Data (Unaudited)

The following is a summary of net profits income, distributable income and distributable income per unit by quarter for 2005 and 2004:

	Net Profits Income		Distributable Income		Distributable Income per Unit
2005
First Quarter	$	4,462,096	$	4,340,544	$	0.723424
Second Quarter		4,589,164		4,453,848		0.742308
Third Quarter		5,069,110		5,039,088		0.839848
Fourth Quarter		6,487,591		6,433,956		1.072326
	$	20,607,961	$	20,267,436	$	3.377906
2004
First Quarter	$	3,116,138	$	3,045,984	$	0.507664
Second Quarter		3,658,858		3,555,792		0.592632
Third Quarter		4,017,397		3,928,740		0.654790
Fourth Quarter		4,430,024		4,393,542		0.732257
	$	15,222,417	$	14,924,058	$	2.487343

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Bank of America, N.A., as Trustee for the Cross Timbers Royalty Trust:

We have audited the accompanying statements of assets, liabilities, and trust corpus of the Cross Timbers Royalty Trust as of December 31, 2005 and 2004, and the related statements of distributable income and changes in trust corpus for each of the years in the three-year period ended December 31, 2005. These financial statements are the responsibility of the trustee. Our responsibility is to express an opinion on these financial statements based on our audits.

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

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

In our opinion, the financial statements referred to above present fairly, in all material respects, the assets, liabilities, and trust corpus of the Cross Timbers Royalty Trust as of December 31, 2005 and 2004 and its distributable income and changes in trust corpus for each of the years in the three-year period ended December 31, 2005 in conformity with the modified cash basis of accounting described in Note 2.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of the Cross Timbers Royalty Trust’s internal control over financial reporting as of December 31, 2005, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated March 16, 2006 expressed an unqualified opinion on the trustee’s assessment of, and the effective operation of, internal control over financial reporting.

KPMG LLP

Dallas, Texas

March 16, 2006

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Bank of America, N.A., as Trustee for the Cross Timbers Royalty Trust:

We have audited the trustee’s assessment, included in Trustee’s Report on Internal Control over Financial Reporting under Item 9A of the accompanying Annual Report on Form 10-K, that Cross Timbers Royalty Trust maintained effective internal control over financial reporting as of December 31, 2005, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The trustee of the Cross Timbers Royalty Trust is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on the trustee’s assessment and an opinion on the effectiveness of the trust’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating the trustee’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

The trust’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with the modified cash basis of accounting. The trust’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the trust; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with the modified cash basis of accounting, and that receipts and expenditures of the trust are being made only in accordance with authorizations of the trustee; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the trust’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the trustee’s assessment that Cross Timbers Royalty Trust maintained effective internal control over financial reporting as of December 31, 2005, is fairly stated, in all material respects, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Also, in our opinion, Cross Timbers Royalty Trust maintained, in all material respects, effective internal control over financial reporting as of December 31, 2005, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the statements of assets, liabilities, and trust corpus of the Cross Timbers Royalty Trust as of December 31, 2005 and 2004, and the related statements of distributable income and changes in trust corpus for each of the years in the three-year period ended December 31, 2005, and our report dated March 16, 2006 expressed an unqualified opinion on those financial statements and included an explanatory paragraph that described the trust’s method of accounting as explained in Note 2 to the financial statements.

KPMG LLP

Dallas, Texas

March 16, 2006

CROSS TIMBERS ROYALTY TRUST

901 Main Street, 17^th Floor

P.O. Box 830650

Dallas, Texas 75283-0650

(877) 228-5084

Bank of America, N.A., Trustee

A copy of the Cross Timbers Royalty Trust Form 10-K has been provided with this Annual Report. Additional copies of this Annual Report and Form 10-K will be provided to unitholders without charge upon request. Copies of exhibits to the Form 10-K may be obtained upon request or from the trust’s web site at www.crosstimberstrust.com.

WEB SITE

www.crosstimberstrust.com

AUDITORS

KPMG LLP

Dallas, Texas

LEGAL COUNSEL

Thompson & Knight L.L.P.

Dallas, Texas

TAX COUNSEL

Winstead Sechrest & Minick P.C.

Houston, Texas

TRANSFER AGENT AND REGISTRAR

Mellon Investor Services, L.L.C.

www.melloninvestor.com

EX-23.1

EXHIBIT 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Cross Timbers Royalty Trust

Dallas, Texas:

We consent to the incorporation by reference in the Post-Effective Amendment No. 1 to the Registration Statement No. 33-55784 on Form S-8 and Registration Statement No. 333-91460 on Form S-8 of XTO Energy Inc. of our reports dated March 16, 2006, with respect to the statements of assets, liabilities and trust corpus of Cross Timbers Royalty Trust as of December 31, 2005 and 2004, and the related statements of distributable income and changes in trust corpus for each of the years in the three-year period ended December 31, 2005, the trustee’s assessment of the effectiveness of internal control over financial reporting as of December 31, 2005 and the effectiveness of internal control over financial reporting as of December 31, 2005, which reports appear in the December 31, 2005 Annual Report on Form 10-K of Cross Timbers Royalty Trust.

KPMG LLP

Dallas, Texas

March 16, 2006

EX-23.2

EXHIBIT 23.2

[LETTERHEAD OF MILLER AND LENTS, LTD. APPEARS HERE]

March 16, 2006

Cross Timbers Royalty Trust

P.O. Box 830650

Dallas, TX 75283-0650

Re: Cross Timbers Royalty Trust

2005 Annual Report on Form 10-K

Gentlemen:

The firm of Miller and Lents, Ltd., consents to the use of its name and to the use of its report dated February 20, 2006, regarding the Cross Timbers Royalty Trust Proved Reserves and Future Net Revenues as of December 31, 2005, in the 2005 Annual Report on Form 10-K.

Miller and Lents, Ltd., has no interests in Cross Timbers Royalty Trust or in any affiliated companies or subsidiaries and is not to receive any such interest as payment for such reports and has no director, officer, or employee otherwise connected with Cross Timbers Royalty Trust. We are not employed by Cross Timbers Royalty Trust on a contingent basis.

Yours very truly,
MILLER AND LENTS, LTD.
By	/S/ JAMES PEARSON
	James Pearson Chairman

EX-31

EXHIBIT 31

CERTIFICATIONS

I, Nancy G. Willis, certify that:

1. I have reviewed this annual report on Form 10-K of Cross Timbers Royalty Trust, for which Bank of America, N.A. acts as Trustee;

2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;

3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, distributable income and changes in trust corpus of the registrant as of, and for, the periods presented in this annual report;

4. I am responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)), or for causing such controls and procedures to be established and maintained, for the registrant and I have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under my supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to me by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under my supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report my conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. I have disclosed, based on my most recent evaluation of internal control over financial reporting, to the registrant’s auditors:

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

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

Date: March 16, 2006

By	/S/ NANCY G. WILLIS
	Nancy G. Willis Vice President Bank of America, N.A.

EX-32

EXHIBIT 32

Certification pursuant to 18 U.S.C. Section 1350,

as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

In connection with the Annual Report of Cross Timbers Royalty Trust (the “Trust”) on Form 10-K for the year ended December 31, 2005 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), the undersigned, not in its individual capacity but solely as the trustee of the Trust, certifies pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to its knowledge:

(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Trust.

	Bank of America, N.A., Trustee for Cross Timbers Royalty Trust
March 16, 2006	By	/S/ NANCY G. WILLIS
		Nancy G. Willis Vice President