Cross Timbers Royalty Trust 10K 2008 Annual report | CRT Filing

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 2008 and 2007:


	Sales Price				Distributions per Unit
Quarter	High		Low		Distributions per Unit
2008
First	$	52.10	$	40.35	$	1.127713
Second		60.59		45.50		1.396719
Third		64.25		43.03		1.519035
Fourth		48.90		21.52		1.113603

					$	5.157070

2007
First	$	49.99	$	40.17	$	0.758075
Second		45.60		41.90		0.846160
Third		44.65		37.83		0.830440
Fourth		43.03		39.00		0.866279

					$	3.300954

At December 31, 2008, there were 6,000,000 units outstanding and approximately 360 unitholders of record; 5,808,948 of these units were held by depository institutions.

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:


	2008						2007						2006
	Monthly Average			Annual Total			Monthly Average			Annual Total			Monthly Average			Annual Total
Net profits income:
—90% net profits interests	$	0.341	(a)	$	4.086	(a)	$	0.241		$	2.892		$	0.299	(b)	$	3.592	(b)
—75% net profits interests		0.094			1.132			0.039			0.473			0.058			0.702
Administration expense (net of interest income)		(0.005	)		(0.061	)		(0.005	)		(0.064	)		(0.004	)		(0.053	)

Total Distribution	$	0.430	(a)	$	5.157	(a)	$	0.275		$	3.301		$	0.353	(b)	$	4.241	(b)

(a)	Includes proceeds related to lawsuit settlements that increased the 2008 distribution by $0.36 per unit (a monthly average of $0.03 per unit).

(b)	Includes proceeds related to a lawsuit settlement that increased the 2006 distribution by $0.33 per unit (a monthly average of $0.028 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 2008 and held them throughout 2008 would be entitled to a cost depletion deduction of approximately 7% of his cost. Assuming a cost of $42.00 per unit, cost depletion would offset approximately 58% of 2008 taxable trust income. Assuming a 30% tax rate, the 2008 taxable equivalent return as a percentage of unit cost would be 15%. (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 were subject to a reversion agreement between XTO Energy and an unrelated third party. The agreement called 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. At the time payout occurred, net proceeds payable to the trust and trust distributions to unitholders were reduced. XTO Energy informed the trustee that payout occurred effective with the July 2007 distribution, which was paid on August 14, 2007, thereby reducing the July 2007 distribution and all future distributions by approximately 5%.

TO UNITHOLDERS

We are pleased to present the 2008 Annual Report of Cross Timbers Royalty Trust. This report includes a copy of the trust’s 2008 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, 2008, net profits income totaled $31,311,215. After deducting trust administration expense and adding interest income, distributable income was $30,942,420, or $5.157070 per unit. Distributions for the year were higher than in 2007 primarily because of increased oil and gas prices and lawsuit settlement proceeds received in 2008, partially offset by decreased oil and gas production due in part to payout occurring under the reversion agreement. See “Trustee Discussion and Analysis—Years Ended December 31, 2008, 2007 and 2006—Other Proceeds” and “Trustee Discussion and Analysis—Years Ended December 31, 2008, 2007 and 2006—Reversion Agreement.”

Natural gas prices for 2008 averaged $11.70 per Mcf for sales from the underlying properties, a 46% increase from the 2007 average price of $8.01 per Mcf. Excluding the effects of the lawsuit settlements in 2008, the average gas price was $11.03. Gas sales volumes from the underlying properties for the year ended December 31, 2008 totaled 2,079,350 Mcf, or 5,681 Mcf per day, a 12% decrease from 2007 production of 2,367,917 Mcf, or 6,487 Mcf per day. Gas sales volumes decreased primarily because of natural production decline, the timing of cash receipts and payout occurring under the reversion agreement.

The average oil price increased to $99.68 per Bbl, up 67% from the 2007 average price of $59.70 per Bbl. Oil sales volumes from the underlying properties during 2008 were 224,296 Bbls, or 613 Bbls per day, a 9% decrease from 2007 production of 246,966 Bbls, or 677 Bbls per day. Oil sales volumes decreased primarily because of natural production decline, payout occurring under the reversion agreement and prior period volume adjustments in 2008, partially offset by increased production from new wells and workovers.

As of December 31, 2008, proved reserves for the underlying properties were estimated by independent engineers to be 2.1 million Bbls of oil and 28.8 Bcf of natural gas. Based on an allocation of these reserves, proved reserves attributable to the net profits interests were estimated to be 849,000 Bbls of oil and 25.6 Bcf of natural gas.

From year-end 2007 to 2008, oil reserves for the underlying properties decreased 32% and oil reserves attributable to the net profits interests decreased 51% primarily because of revisions due to lower year-end prices and 2008 production. Year-end gas reserves for the underlying properties, as well as for the net profits interests, decreased approximately 8% from 2007 to 2008 primarily because of production and lower year-end prices, 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, 2008 are $128.7 million. Using an annual discount factor of 10%, the present value of estimated future net cash flows at December 31, 2008 is $64.5 million. Proved reserve estimates and related future net cash flows have been determined based on a year-end West Texas Intermediate posted oil price of $41.22 per Bbl and a year-end average realized gas price of $4.27 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 2009, trust distributions are considered portfolio income, rather than passive income. Unitholders should consult their tax advisors for further information.

Cross Timbers Royalty Trust

By:	U.S. Trust, Bank of America

Private Wealth Management, 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, 2008 is approximately 11 years. This index is calculated using total proved reserves and estimated 2009 production for the underlying properties. The projected 2009 production is from proved developed producing reserves as of December 31, 2008. Based on estimated future net cash flows at year-end oil and gas prices, the proved reserves of the underlying properties are approximately 23% oil and 77% 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.

90% Net Profits Interests

Royalty and overriding royalty properties underlying the 90% net profits interests represent 89% of the discounted future net cash flows from trust proved reserves at December 31, 2008. Approximately 84% of the discounted future net cash flows from the 90% net profits interests is from gas reserves, totaling 25.5 Bcf. Oil reserves allocated to the 90% net profits interests are primarily located in West Texas and are estimated to be 532,000 Bbls at December 31, 2008.

Because the properties related to the 90% net profits interests are primarily 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 gas production accounted for approximately 75% of the trust’s gas sales volumes and 44% of the net profits income for 2008. As of December 31, 2008, trust proved gas reserves in this region are estimated to be 20.8 Bcf, or 81% of total trust gas reserves.

Most of the trust’s San Juan Basin gas has been approved for increased density drilling. In 1999, the Mesaverde was approved for increased density drilling, and in 2002 the Fruitland Coal was approved for increased density drilling, which doubled the number of drill wells allowed per spacing unit. XTO Energy has advised the trustee that the trust has received net proceeds from additional development wells in recent years and that it believes operators will continue to pursue increased density drilling, but the potential effect on the trust is unknown.

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 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 317,000 Bbls at year-end 2008. Based on year-end oil and gas prices, proved reserves from these interests represent 11% of the discounted future net cash flows of the trust’s proved reserves at December 31, 2008.

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 2008 development costs were $1,453,290, down 34% from 2007 development costs of $2,199,001. Development costs were lower in 2008 because of decreased development activity related to Texas and Oklahoma properties underlying the 75% net profits interest. January and February 2009 development costs totaled approximately $231,000, and were primarily incurred in fourth quarter 2008.

As reported to XTO Energy by unit operators in February of each year, budgeted development costs were $1.2 million for 2008 and $2.3 million for 2007. 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 $756,000 for 2009 and $1.5 million for 2010.

There were no excess costs in 2006, 2007 or 2008. For information regarding the effect of excess costs on trust net profits income, see “Trustee’s Discussion and Analysis—Years Ended December 31, 2008, 2007 and 2006—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, 2008:


	Underlying Properties		Net Profits Interests
	Proved Reserves (a)		Proved Reserves (a) (b)		Future Net Cash Flows from Proved Reserves (a) (c)
	Oil (Bbls)	Gas (Mcf)	Oil (Bbls)	Gas (Mcf)	Undiscounted		Discounted
(in thousands)

90% Net Profits Interests
San Juan Basin	36	23,062	33	20,755	$	77,688	$	36,553
Other New Mexico	56	192	50	192		2,836		1,477
Texas	454	3,372	408	3,034		29,451		15,441
Oklahoma	46	1,755	41	1,482		7,745		4,140

Total	592	28,381	532	25,463		117,720		57,611


75% Net Profits Interests
Texas	679	253	147	54		5,444		3,305
Oklahoma	848	202	170	41		5,579		3,557

Total	1,527	455	317	95		11,023		6,862

TOTAL	2,119	28,836	849	25,558	$	128,743	$	64,473

(a)

Based on year-end oil and gas prices. Discounted estimated future net cash flows from proved reserves decreased 56% from year-end 2007 to 2008, primarily because of a 33% decrease in year-end natural gas prices and a 56% decrease in year-end oil prices. 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, 2008, 2007 and 2006

Net profits income for 2008 was $31,311,215, as compared with $20,189,267 for 2007 and $25,767,154 for 2006. The 55% increase in net profits income from 2007 to 2008 was primarily because of increased oil and gas prices and lawsuit settlement proceeds received in 2008, partially offset by decreased oil and gas production due in part to payout occurring under the reversion agreement. The 22% decrease in net profits income from 2006 to 2007 was primarily because of decreased oil and gas production due in part to payout occurring under the reversion agreement, lawsuit settlement proceeds received in 2006 and higher development costs. See “Reversion Agreement” and “Other Proceeds” below. During 2008, 2007 and 2006, 59%, 69% and 68%, respectively, of net profits income was derived from gas sales.

Trust administration expense was $389,863 in 2008 as compared to $423,075 in 2007 and $376,592 in 2006. Decreased administrative expense from 2007 to 2008 is primarily due to the timing of expenditures related to unitholder tax reporting. Increased administrative expense from 2006 to 2007 is primarily due to the timing of expenditures related to additional unitholder tax reporting. Interest income was $21,068 in 2008, $39,532 in 2007 and $57,616 in 2006. 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 9% from 2007 to 2008 compared to a 9% decrease from 2006 to 2007. Oil sales volumes in 2008 decreased from 2007 primarily because of natural production decline, payout occurring under the reversion agreement and prior period volume adjustments in 2008, partially offset by increased production from new wells and workovers. Oil sales volumes in 2007 decreased from 2006 primarily because of natural production decline, timing of cash receipts and payout occurring under the reversion agreement, partially offset by increased production from new wells and workovers. See “Reversion Agreement” below.

Gas. Underlying gas sales volumes decreased 12% from 2007 to 2008 compared to an 11% decrease from 2006 to 2007. Gas sales volumes in 2008 decreased from 2007 primarily because of natural production decline, timing of cash receipts and payout occurring under the reversion agreement. Decreased gas sales volumes in 2007 were primarily because of the natural production decline, timing of cash receipts and payout occurring under the reversion agreement, partially offset by increased production from new wells and workovers. See “Reversion Agreement” below.

Prices

Oil. The average oil price for 2008 was $99.68 per Bbl, 67% higher than the 2007 average oil price of $59.70, which was 1% higher than the 2006 average price of $59.05. Oil prices have risen primarily because of increasing global demand and supply shortage, inadequate sour crude refining capacity, reduced production as a result of tropical storms and political instability in some oil producing countries. In the last few months of 2007 and the first half of 2008, narrowing excess worldwide capacity, weakness in the dollar and continuing tension in the Middle East caused prices to reach record levels above $147.00 per Bbl in July 2008. However, lower demand as a result of the deepening U.S. recession and slowing global economy, the tightened credit markets and rising crude oil supplies have caused oil prices to decline sharply in the second half of 2008. Oil prices are expected to remain volatile. The average NYMEX price for November 2008 through January 2009 was $46.91 per Bbl. At February 18, 2009, the average NYMEX oil price for the following 12 months was $42.98 per Bbl. Recent trust oil prices have averaged approximately 7% lower than the NYMEX price.

Gas. The 2008 average gas price was $11.70 per Mcf, a 46% increase from the 2007 average gas price of $8.01, which was 9% lower than the 2006 average price of $8.79. Excluding the effects of the lawsuit settlements in 2008 and 2006, the average gas price increased 38% from $8.01 per Mcf in 2007 to $11.03 per Mcf in 2008 and decreased 2% from $8.18 per Mcf in 2006 to $8.01 per Mcf in 2007. See “Other Proceeds” below. Beginning in 2006 and into 2007, gas prices trended lower primarily because of adequate natural gas supply inventory due to warmer than normal winter weather in 2006 and the absence of hurricane activity in the Gulf of Mexico. Much colder temperatures in early 2007 caused prices to partially rebound. As a result of tighter storage levels and higher oil prices, gas prices increased in the first half of 2008 and reached as high as $13.00 per MMBtu in July. Due to concerns of oversupply from shale gas development, declining demand due to the deepening U.S. recession, falling oil prices and increased gas storage, recent gas prices have declined. Natural gas prices are expected to remain volatile. The average NYMEX price for fourth quarter 2008 was $6.38 per MMBtu. Recent trust gas prices have averaged approximately 8% higher than the NYMEX price. At February 18, 2009, the average NYMEX gas price for the following 12 months was $4.97 per MMBtu.

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. Significantly lower oil prices caused costs to exceed revenues by a total of $161,296 ($120,972 net to the trust) on properties underlying the Texas working interest in January and February 2009 and by $143,485 ($107,614 net to the trust) on properties underlying the Oklahoma working interest in February 2009. However, these excess costs did not reduce net proceeds from the remaining conveyances. With continued downward pressure on oil and gas prices from the deepening U.S. recession, excess costs are expected to continue over the near term resulting in lower monthly distributions.

Total costs deducted in the calculation of net profits income were $11.4 million in 2008, $10.7 million in 2007 and $10.4 million in 2006. The 7% increase in costs from 2007 to 2008 is attributable to higher production taxes associated with increased revenues and increased production expense related to the timing of cash disbursements and overall price increases as well as increased power and fuel and workover costs, partially offset by lower development costs and lower property taxes due to the timing of cash disbursements. The 3% increase in costs from 2006 to 2007 is attributable to higher development costs, partially offset by lower property taxes related to the timing of cash disbursements, lower production taxes associated with decreased

revenues and decreased production expense due to decreased power and fuel and carbon dioxide injection costs.

Unit operators of the properties underlying the 75% net profits interests have reported total budgeted development costs, net to the underlying properties, of approximately $756,000 for 2009 and $1.5 million for 2010, as compared to budgeted development costs of $1.2 million and actual development costs of $1.5 million for 2008. 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 2008 includes lawsuit settlements of $2,430,326 related to underpayment of royalties on underlying properties in the San Juan Basin. Included in these settlements was interest of $1,024,815 and additional gas revenue of $1,405,511, which increased the 2008 average gas sales price by $0.67 per Mcf. The total settlements, net to the trust, were $2,187,294, or $0.36 per unit.

The calculation of net profits income for 2006 includes a lawsuit settlement of $2,209,927 related to underpayment of royalties on underlying properties in the San Juan Basin. Included in this settlement is interest of $566,848 and additional gas revenue of $1,643,079, which increased the 2006 average gas sales price by $0.61 per Mcf. The total settlement, net to the trust, was $1,988,934, or $0.33 per unit.

State of Texas Margin Tax

In May 2006, the State of Texas modified its franchise tax to impose a “margin tax” of up to 1% on revenues less certain costs, as specified in the legislation, generated from Texas activities beginning in 2007. Entities subject to the tax generally include trusts, unless otherwise exempt, and various other types of entities. Trusts that meet statutory requirements are generally exempt from the margin tax as “passive entities”. The trust has been advised by Texas tax counsel that the trust is exempt from margin tax as a passive entity. However, each unitholder that is a business entity or limited liability entity subject to the margin tax is generally required to include its share of the trust’s revenues in its margin tax computation.

Unitholders are urged to consult their own tax advisors regarding the requirements for filing state tax returns.

Reversion Agreement

Fourth Quarter 2008 and 2007

During the quarter ended December 31, 2008, the trust received net profits income totaling $6,733,010, compared with fourth quarter 2007 net profits income of $5,237,599. This 29% increase is primarily attributable to higher oil and gas prices, partially offset by decreased oil and gas production.

Administration expense was $54,205 and trust interest income was $2,813, resulting in fourth quarter 2008 distributable income of $6,681,618, or $1.113603 per unit. Distributable income for fourth quarter 2007 was $5,197,674, or $0.866279 per unit. Distributions to unitholders for the quarter ended December 31, 2008 were:


Record Date	Payment Date	Per Unit
October 31, 2008	November 17, 2008	$0.467223
November 28, 2008	December 12, 2008	0.393836
December 31, 2008	January 15, 2009	0.252544

		$1.113603

Volumes

Fourth quarter 2008 underlying oil sales volumes were 51,603 Bbls, or 13% lower than 2007 levels and underlying gas sales volumes were 500,387 Mcf, or 12% lower than 2007 levels. Oil sales volumes decreased in 2008 primarily because of natural production decline and the timing of cash receipts. Gas sales volumes decreased in 2008 primarily because of natural production decline and prior period volume adjustments in 2008.

Prices

The average fourth quarter 2008 oil price was $95.41 per Bbl, 33% higher than the fourth quarter 2007 average price of $71.84. The average fourth quarter 2008 gas price was $11.86 per Mcf, 49% higher than the fourth quarter 2007 average price of $7.97. For further information about oil and gas prices, see “Years Ended December 31, 2008, 2007 and 2006 – Prices” above.

Costs

Costs deducted in the calculation of fourth quarter 2008 net profits income increased $308,844, or 11%, from fourth quarter 2007. This increase was primarily related to higher production taxes associated with increased revenues and increased production expense related to the timing of cash disbursements and overall price increases as well as increased power and fuel, carbon dioxide injection and maintenance costs, partially offset by lower development costs.

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)						Quarter Ended December 31 (a)
	2008		2007		2006		2008		2007
Sales Volumes
Oil (Bbls) (b)
Underlying properties		224,296		246,966		270,112		51,603		59,201
Average per day		613		677		740		561		643
Net profits interests		129,041		111,307		143,067		25,792		28,396

Gas (Mcf) (b)
Underlying properties		2,079,350		2,367,917		2,666,477		500,387		568,188
Average per day		5,681		6,487		7,305		5,439		6,176
Net profits interests		1,825,147		2,072,879		2,329,603		439,191		499,789

Average Sales Price
Oil (per Bbl)	$	99.68	$	59.70	$	59.05	$	95.41	$	71.84
Gas (per Mcf) (c)(d)	$	11.70	$	8.01	$	8.79	$	11.86	$	7.97

Revenues
Oil sales	$	22,358,808	$	14,744,040	$	15,949,207	$	4,923,442	$	4,253,158
Gas sales (c)(d)		24,331,383		18,977,522		23,443,948		5,932,777		4,529,806

Total Revenues		46,690,191		33,721,562		39,393,155		10,856,219		8,782,964


Costs
Taxes, transportation and other		5,357,997		4,518,944		5,501,724		1,452,939		1,192,581
Production expense (e)		4,603,581		3,940,747		4,166,959		1,330,787		994,104
Development costs		1,453,290		2,199,001		724,285		260,380		548,577

Total Costs		11,414,868		10,658,692		10,392,968		3,044,106		2,735,262


Other Proceeds
Interest income (c)(d)		1,024,815		—		566,848		—		—

Net Proceeds	$	36,300,138	$	23,062,870	$	29,567,035	$	7,812,113	$	6,047,702

Net Profits Income	$	31,311,215	$	20,189,267	$	25,767,154	$	6,733,010	$	5,237,599

(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 quarter 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)

In 2008, $2,430,326 was received related to lawsuit settlements for underpayment of royalties of $1,405,511 on certain San Juan Basin properties. Included in these settlements was interest of $1,024,815. These settlements increased the average gas sale price by $0.67 for 2008. The total settlements, net to the trust, were $2,187,294, or $0.36 per unit.

(d)

In 2006, $2,209,927 was received related to a lawsuit settlement for underpayment of royalties of $1,643,079 on certain San Juan Basin properties. Included in this settlement was interest of $566,848. This settlement increased the average gas sales price by $0.61 for 2006. The total settlement, net to trust, was $1,988,934, or $0.33 per unit.

(e)

Includes an overhead charge which is deducted and retained by XTO Energy. As of December 31, 2008, this charge was $31,831 per month (including a monthly overhead charge of $2,830 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.

Cross Timbers Royalty Trust

STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS


	December 31
	2008		2007
Assets
Cash and short-term investments	$	1,514,797	$	1,757,903
Interest to be received		467		2,245
Net profits interests in oil and gas properties—net (Notes 1 and 2)		17,255,761		18,387,752

	$	18,771,025	$	20,147,900

Liabilities and Trust Corpus
Distribution payable to unitholders	$	1,515,264	$	1,760,148
Trust corpus (6,000,000 units of beneficial interest authorized and outstanding)		17,255,761		18,387,752

	$	18,771,025	$	20,147,900

STATEMENTS OF DISTRIBUTABLE INCOME


	Year Ended December 31
	2008		2007		2006
Net profits income	$	31,311,215	$	20,189,267	$	25,767,154
Interest income		21,068		39,532		57,616

Total income		31,332,283		20,228,799		25,824,770
Administration expense		389,863		423,075		376,592

Distributable income	$	30,942,420	$	19,805,724	$	25,448,178

Distributable income per unit (6,000,000 units)	$	5.157070	$	3.300954	$	4.241363

See Accompanying Notes to Financial Statements.

Cross Timbers Royalty Trust

STATEMENTS OF CHANGES IN TRUST CORPUS


	Year Ended December 31
	2008			2007			2006
Trust corpus, beginning of year	$	18,387,752		$	19,679,502		$	21,204,723
Amortization of net profits interests		(1,131,991	)		(1,291,750	)		(1,525,221	)
Distributable income		30,942,420			19,805,724			25,448,178
Distributions declared		(30,942,420	)		(19,805,724	)		(25,448,178	)

Trust corpus, end of year	$	17,255,761		$	18,387,752		$	19,679,502

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 (Note 5). The trust’s initial public offering was in February 1992.

Bank of America, N.A. is the trustee of the trust. In 2007 the Bank of America private wealth management group officially became known as “U.S. Trust, Bank of America Private Wealth Management.” The legal entity that serves as the trustee of the trust did not change, and references in this Annual Report to U.S. Trust, Bank of America Private Wealth Management shall describe the legal entity Bank of America, N.A. 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 U.S. 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.

In December 2008, the Securities and Exchange Commission (SEC) released Final Rule,Modernization of Oil and Gas Reporting.The new disclosure requirements include provisions that permit the use of new technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserves volumes. The new requirements also will allow companies to disclose their probable and possible reserves to investors. In addition, the new disclosure requirements require companies to: (a) report the independence and qualifications of its reserves preparer or auditor; (b) file reports when a third party is relied upon to prepare reserves estimates or conducts a reserves audit; and (c) report oil and gas reserves using an average price based upon the prior 12-month period rather than year-end prices. The new disclosure requirements are effective for financial statements for fiscal years ending on or after December 31, 2009. The effect of adopting the SEC rule has not been determined, but it is not expected to have a significant effect on our reported financial position or distributable income.

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 $43,844,688 as of December 31, 2008 and $42,712,697 as of December 31, 2007.

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. (Note 8).

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. (Note 9).

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.

The trust is a widely held fixed investment trust (“WHFIT”) classified as a non-mortgage widely held fixed investment trust (“NMWHFIT”) for federal income tax purposes. The trustee is the representative of the trust that will provide tax information in accordance with the applicable U.S. Treasury Regulations governing the information reporting requirements of the trust as a WHFIT or a NMWHFIT.

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 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, 2008 was $31,831 per month, or $381,972 annually (net to the trust of $286,479 annually). XTO Energy also deducts an overhead charge as operator of the Penwell Unit. As of December 31, 2008, overhead attributable to the Penwell Unit was $2,830 per month, or $33,960 annually (net to the trust of $25,470 annually). These overhead charges are subject to an annual adjustment based on an oil and gas industry index.

6. Reversion Agreement

7. 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 the conclusion. Should the trust be 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.

In May 2006, the State of Texas modified its franchise tax to impose a “margin tax” of up to 1% on revenues less certain costs, as specified in the legislation, generated from Texas activities beginning in 2007. Entities subject to the tax generally include trusts, unless otherwise exempt, and various other types of entities. Trusts that meet statutory requirements are generally exempt from the margin tax as “passive entities.” The trust has been advised by Texas tax counsel that the trust is exempt from margin tax as a passive entity. However, each unitholder that is a business entity or limited liability entity subject to the margin tax is generally required to include its share of the trust’s revenues in its margin tax computation.

8. Purchaser Adjustments and Lawsuit Settlements

From time-to-time, XTO Energy receives net proceeds for the underlying properties related to significant prior period purchaser adjustments and lawsuit settlements, including related interest income. Because of the size and nature of these adjustments and settlements, XTO Energy has informed the trustee that it believes these should be considered one-time, or nonrecurring, events. Since most of the properties in the trust are nonoperated, these adjustments are generally not known to XTO Energy until reported by the purchaser. These items are included and reported in net profits income in the month received by the trust, which is generally the month following receipt by XTO Energy.

In 2008, the calculation of net profits income includes proceeds from lawsuit settlements of $2,430,326 related to underpayment of royalties on underlying properties in the San Juan Basin. Included in these settlements was interest of $1,024,815 and additional gas revenue of $1,405,511. The total settlements, net to the trust, were $2,187,294, or $0.36 per unit.

In 2006, the calculation of net profits income includes proceeds from a lawsuit settlement of $2,209,927 related to underpayment of royalties on underlying properties in the San Juan Basin. Included in this settlement is interest of $566,848 and additional gas revenue of $1,643,079. The total settlement, net to the trust, was $1,988,934, or $0.33 per unit.

9. Excess Costs

Significantly lower oil prices caused costs to exceed revenues by a total of $161,296 ($120,972 net to the trust) on properties underlying the Texas working interest in January and February 2009 and by $143,485 ($107,614 net to the trust) on properties underlying the Oklahoma working interest in February 2009. However, these costs did not reduce net proceeds from the remaining conveyances. With continued downward pressure on realized oil and gas prices from the deepening U.S. recession, excess costs are expected to continue over the near term resulting in lower monthly distributions.

10. 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.

11. Quarterly Financial Data (Unaudited)

The following is a summary of net profits income, distributable income and distributable income per unit by quarter for 2008 and 2007:


	Net Profits Income		Distributable Income		Distributable Income per Unit
2008
First Quarter	$	6,885,854	$	6,766,278	$	1.127713
Second Quarter		8,528,354		8,380,314		1.396719
Third Quarter		9,163,997		9,114,210		1.519035
Fourth Quarter		6,733,010		6,681,618		1.113603

	$	31,311,215	$	30,942,420	$	5.157070

2007
First Quarter	$	4,699,186	$	4,548,450	$	0.758075
Second Quarter		5,222,836		5,076,960		0.846160
Third Quarter		5,029,646		4,982,640		0.830440
Fourth Quarter		5,237,599		5,197,674		0.866279

	$	20,189,267	$	19,805,724	$	3.300954

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, 2008 and 2007 and related statements of distributable income and changes in trust corpus for each of the years in the three-year period ended December 31, 2008. We also have audited Cross Timbers Royalty Trust’s internal control over financial reporting as of December 31, 2008, based on criteria established inInternal Control—Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The trustee of Cross Timbers Royalty Trust is responsible for these financial statements, 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 these financial statements and an opinion on the trust’s internal control over financial reporting 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 audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by the trustee, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

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.

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 financial statements referred to above present fairly, in all material respects, the assets, liabilities, and trust corpus of Cross Timbers Royalty Trust as of December 31, 2008 and 2007, and its distributable income and changes in trust corpus for each of the years in the three-year period ended December 31, 2008, in conformity with the modified cash basis of accounting described in note 2. Also in our opinion, Cross Timbers Royalty Trust maintained, in all material respects, effective internal control over financial reporting as of December 31, 2008, based on control criteria established inInternal Control—Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission.

KPMG LLP

Fort Worth, Texas

February 25, 2009

CROSS TIMBERS ROYALTY TRUST

901 Main Street, 17^th Floor

P.O. Box 830650

Dallas, Texas 75283-0650

(877) 228-5084

U.S. Trust, Bank of America

Private Wealth Management, 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 PC

Houston, Texas

TRANSFER AGENT AND REGISTRAR

BNY Mellon Shareowner Services

Positive
Negative
Uncertain
Constraining
Legalese
Litigious
Readability	H.S. freshman Bad

Cross Timbers Royalty Trust (CRT) 10-K2008 FY Annual report

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