Cross Timbers Royalty Trust (CRT) 10-K 2005 FY Annual report

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