SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

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

THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2002 Commission file number 1-10982

Cross Timbers Royalty Trust

(Exact name of registrant as specified in the Cross Timbers Royalty Trust Indenture)

Texas	75-6415930
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

Bank of America, N.A. Trustee P.O. Box 830650 Dallas, Texas	75283-0650
(Address of principal executive offices)	(Zip Code)

Registrant’s telephone number including area code: (877) 228-5084

Securities registered pursuant to Section 12(b) of the Act:

Title of each class	Name of each exchange on which registered
Units of Beneficial Interest	New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act:    None

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days. Yes  x     No  ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  x

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Securities Exchange Act of 1934). Yes  ¨    No  x

The aggregate market value of the units of beneficial interest of the trust, based on the closing price on the New York Stock Exchange as of June 28, 2002 (the last business day of its most recently completed second fiscal quarter), held by non-affiliates of the registrant on that date was approximately $72 million.

At March 3, 2003, there were 6,000,000 units of beneficial interest of the trust outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Listed below is the only document parts of which are incorporated herein by reference and the parts of this report into which the document is incorporated:

2002 Annual Report to Unitholders—Part II

TABLE OF CONTENTS

		Page
	PART I
Item 1.	Business	1
Item 2.	Properties	3
Item 3.	Legal Proceedings	10
Item 4.	Submission of Matters to a Vote of Security Holders	10
	PART II
Item 5.	Market for Units of the Trust and Related Security Holder Matters	11
Item 6.	Selected Financial Data	11
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	11
Item 7a.	Quantitative and Qualitative Disclosures about Market Risk	14
Item 8.	Financial Statements and Supplementary Data	14
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	14
	PART III
Item 10.	Directors and Executive Officers of the Registrant	15
Item 11.	Executive Compensation	15
Item 12.	Security Ownership of Certain Beneficial Owners and Management	15
Item 13.	Certain Relationships and Related Transactions	16
Item 14.	Controls and Procedures	16
	PART IV
Item 15.	Exhibits, Financial Statement Schedules and Reports on Form 8-K	16
	Signatures	18
	Certifications	19

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PART I

Item 1.    Business

Cross Timbers Royalty Trust is an express trust created under the laws of Texas pursuant to the Cross Timbers Royalty Trust Indenture entered into on February 12, 1991 between predecessors of XTO Energy Inc., as grantors, and NCNB Texas National Bank, as trustee. Bank of America, N.A., successor of NCNB Texas National Bank, is now the trustee of the trust. The principal office of the trust is located at 901 Main Street, Dallas, Texas 75202 (telephone number 877-228-5084).

The trust’s internet web site is www.crosstimberstrust.com. As of March 31, 2003, we make available free of charge, through our web site, our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and all amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934. These reports are accessible through our internet web site as soon as reasonably practicable after we electronically file such material with, or furnish it to, the Securities and Exchange Commission.

On February 12, 1991, the predecessors of XTO Energy (formerly known as Cross Timbers Oil Company) conveyed defined net profits interests to the trust under five separate conveyances:

— one in each of the states of Texas, Oklahoma and New Mexico, to convey a 90% defined net profits interest carved out of substantially all royalty and overriding royalty interests owned by the predecessors in those states, and

— one in each of the states of Texas and Oklahoma, to convey a 75% defined net profits interest carved out of specific working interests owned by the predecessors in those states.

The conveyance of these net profits interests was effective for production from October 1, 1990. The net profits interests and the underlying properties are further described under Item 2.

In exchange for the conveyance of the net profits interests to the trust, the predecessors of XTO Energy received 6,000,000 units of beneficial interest of the trust. Predecessors of XTO Energy distributed units to their owners in February 1991 and November 1992, and in February 1992, sold units in the trust’s initial public offering. Units are listed and traded on the New York Stock Exchange under the symbol “CRT.” During 1996 and 1997, XTO Energy’s Board of Directors authorized XTO Energy to purchase two million units. As of March 3, 2003, XTO Energy owned 1,360,000 units, or 22.7%, of the outstanding units.

In June 1998 the trust and XTO Energy filed a registration statement with the Securities and Exchange Commission to sell the 1,360,000 units held by XTO Energy. As XTO Energy stated in a related news release, the filing was made in anticipation of better commodity prices and any sale is dependent on an improved market for oil and gas equities. The registration statement was amended in October 2000 and June 2001. As of March 28, 2003, no sales have been made under the registration statement. The trust did not participate in XTO Energy’s decisions to acquire or sell units and will not receive any of the proceeds in the event of such sale.

Under the terms of each of the five conveyances, the trust receives net profits income from the net profits interests on the last business day of each month. Net profits income is determined by XTO Energy by multiplying the net profit percentage (90% or 75%) times net proceeds from the underlying properties for each of the five conveyances during the previous month. Net proceeds are the gross proceeds received from the sale of production, less production costs. For the 90% net profits interests and the 75% net profits interests, “production costs” generally include applicable property taxes, transportation, marketing and other charges. For the 75% net profits interests only, production costs also include capital and operating costs paid (e.g., drilling, production and other direct costs of owning and operating the property) and a monthly overhead charge that is adjusted annually. The monthly overhead charge at December 31, 2002 was $23,470 ($17,603 net to the trust). If production costs

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exceed gross proceeds for any conveyance, such excess is carried forward to the computation of net proceeds for future months until the excess costs (plus interest accrued as specified in the conveyances) are completely recovered. Excess production costs and related accrued interest from one conveyance cannot be used to reduce net proceeds from any other conveyance.

The trust is not liable for any production costs or liabilities attributable to the net profits interests. If at any time the trust receives net profits income in excess of the amount due, the trust is not obligated to return such overpayment, but net profits income payable to the trust for the next month will be reduced by the overpayment, plus interest at the prime rate.

Approximately 20 of the underlying royalty interests in the San Juan Basin burden working interests in properties operated by XTO Energy. Otherwise, XTO Energy does not operate or control any working interests associated with the underlying royalty interests, nor does it operate or control any of the underlying working interest properties.

As a working interest owner, XTO Energy can generally decline participation in any operation and allow consenting parties to conduct such operations, as provided under the operating agreements. XTO Energy also can assign, sell, or otherwise transfer its interest in the underlying properties, subject to the net profits interests, or can abandon an underlying property that is a working interest if it is incapable of producing in paying quantities, as determined by XTO Energy.

To the extent it has the right to do so, XTO Energy is responsible for marketing its production from the underlying properties under existing sales contracts or new arrangements on the best terms reasonably obtainable in the circumstances.

Net profits income received by the trust on or before the last business day of the month generally represents receipts attributable to oil production two months prior and gas production three months prior. The monthly distribution amount to unitholders is determined by:

Adding—

(1) net profits income received,

(2) estimated interest income to be received on the monthly distribution amount, including an adjustment for the difference between the estimated and actual interest received for the prior monthly distribution amount,

(3) cash available as a result of reduction of cash reserves, and

(4) any other cash receipts, and

Subtracting—

(1) liabilities paid and

(2) the reduction in cash available due to establishment of or increase in any cash reserve.

The monthly distribution amount is distributed to unitholders of record within ten business days after the monthly record date. The monthly record date is generally the last business day of the month. The trustee calculates the monthly distribution amount and announces the distribution per unit at least ten days prior to the monthly record date.

The trustee may establish cash reserves for contingencies. Cash held for such reserves, as well as for pending payment of the monthly distribution amount may be invested in federal obligations or certificates of deposit of major banks.

The trustee’s function is to collect the net profits income from the net profits interests, to pay all trust expenses and pay the monthly distribution amount to unitholders. The trustee’s powers are specified by the terms

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of the indenture. The trust cannot engage in any business activity or acquire any assets other than the net profits interests and specific short-term cash investments. The trust has no employees since all administrative functions are performed by the trustee.

Approximately 67% of the net profits income received by the trust during 2002, as well as 71% of the estimated proved reserves of the net profits interests at December 31, 2002 (based on estimated future net cash flows using year-end oil and gas prices), is attributable to natural gas. There has historically been a greater demand for gas during the winter months than the rest of the year. Otherwise, trust income is not subject to seasonal factors, nor dependent upon patents, licenses, franchises or concessions. The trust conducts no research activities.

Item 2.    Properties

The net profits interests are the principal asset of the trust. The trustee cannot acquire any other asset, with the exception of certain short-term investments as specified under Item 1. The trustee is prohibited from selling any portion of the net profits interests unless approved by at least 80% of the unitholders or at such time as trust gross revenue is less than $1,000,000 for two successive years.

The net profits interests comprise:

— the 90% net profits interests which are carved from:

a) producing royalty and overriding royalty interest properties in Texas, Oklahoma and New Mexico, and

b) 11.11% nonparticipating royalty interests in nonproducing properties located primarily in Texas and Oklahoma;

— the 75% net profits interests which are carved from nonoperated working interests in four properties in Texas and three properties in Oklahoma.

All underlying royalties, underlying nonproducing royalties and underlying working interest properties are currently owned by XTO Energy. XTO Energy may sell all or any portion of the underlying properties at any time, subject to and burdened by the net profits interests.

Producing Acreage, Wells and Drilling

Underlying Royalties.    The underlying royalties are royalty and overriding royalty interests primarily located in mature producing oil and gas fields. The most significant producing region in which the underlying royalties are located is the San Juan Basin in northwestern New Mexico. The trust’s estimated proved gas reserves from this region totaled 24.9 Bcf at December 31, 2002, or approximately 80% of trust total gas reserves at that date. XTO Energy estimates that underlying royalties in the San Juan Basin include more than 2,000 gross (approximately 30 net) wells, covering over 60,000 gross acres. Most of these wells are operated by Amoco Production Company or Burlington Resources Oil & Gas Company. Production from conventional gas wells is primarily from the Dakota, Mesaverde and Pictured Cliffs formations.

Approximately 20% of trust 2002 gas sales volumes were from coal seam production in the San Juan Basin. Through the year 2002, sales of certain coal seam gas qualify for a federal income tax credit. See “Regulation—Coal Seam Tax Credit.” In October 2002, regulatory authorities approved increasing the density of coal seam wells drilled in the San Juan Basin from 320 acres to 160 acres on a significant portion of the trust’s acreage. XTO Energy has informed the trustee that it believes most operators of the related properties will pursue such increased density drilling. However, there can be no assurance that any potential development will significantly affect the trust.

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Most of the trust’s San Juan Basin conventional, or non-coal seam, production is from the Mesaverde formation. This formation has been approved for increased density drilling, doubling the number of drill wells allowed to four per spacing unit. XTO Energy has advised the trustee that it believes operators will further develop the Mesaverde formation underlying the net profits interests, and such future development could significantly impact underlying gas sales volumes. Mesaverde drilling in the San Juan Basin increased in 2002, after drilling permits were delayed in 2001 because of environmental concerns.

In the past, additional eastward pipeline capacity was completed in the San Juan Basin, reducing the dependence of San Juan Basin gas on California markets and effectively increasing San Juan Basin gas prices in relation to prices from other regions. Gas-powered electricity generation continues to increase in the southwest U.S., and future pipelines are being discussed to serve the growing demand.

The underlying royalties also include royalties in the Sand Hills field of Crane County, Texas. Most of these properties are operated by ExxonMobil Corporation or ChevronTexaco. The Sand Hills field was discovered in 1931 and includes production from three main intervals, the Tubb, McKnight and Judkins. Development potential for the field includes recompletions and additional infill drilling.

The underlying royalties contain approximately 462,000 gross (approximately 26,000 net) producing acres. Well counts for the underlying royalties cannot be provided because information regarding the number of wells on royalty properties is generally not made available to royalty interest owners.

Underlying Working Interest Properties.    The underlying working interest properties, detailed below, are developed properties undergoing secondary or tertiary recovery operations:

			Ownership of XTO Energy
Unit	County/State	Operator	Working Interest	Revenue Interest
North Cowden	Ector/Texas	Occidental Permian, Ltd.	1.7%	1.4%
North Central Levelland	Hockley/Texas	ExxonMobil Corporation	3.2%	2.1%
Penwell	Ector/Texas	ChevronTexaco	5.2%	4.6%
Sharon Ridge Canyon	Borden/Texas	ExxonMobil Corporation	4.3%	2.8%
Hewitt	Carter/Oklahoma	ExxonMobil Corporation	11.3%	9.9%
Wildcat Jim Penn	Carter/Oklahoma	LeNorman Partners, L.L.C.	8.6%	7.5%
South Graham Deese	Carter/Oklahoma	Lamamco Drilling Company	8.2%	7.0%

The underlying working interest properties consist of 60,154 gross (2,290 net) producing acres. As of December 31, 2002, there were 1,522 gross (70.5 net) productive oil wells, 1,033 gross (42.2 net) injection wells and one well in process of drilling on these properties. During 2002, nine gross (0.2 net) wells were drilled, during 2001, 50 gross (1.4 net) wells were drilled and during 2000, 12 gross (0.2 net) wells were drilled. Four gross (0.1 net) wells drilled in 2002 and nine gross (0.2 net) wells drilled in 2001 were water injection wells.

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Oil and Gas Production

Trust production is recognized in the period net profits income is received, which is the month following receipt by XTO Energy, and generally two months after the time of oil production and three months after gas production. Oil and gas production and average sales prices attributable to the underlying properties and the net profits interests for the three years ended December 31, 2002 were as follows:

	90% Net Profits Interests						75% Net Profits Interests						Total
	2002		2001		2000		2002		2001		2000		2002		2001		2000
Production
Underlying Properties
Oil—Sales (Bbls)		95,789		92,329		86,970		243,186		258,362		257,153		338,975		350,691		344,123
Average per day (Bbls)		263		253		238		666		708		702		929		961		940
Gas—Sales (Mcf)		2,947,897		2,845,132		2,964,687		82,052		87,071		115,914		3,029,949		2,932,203		3,080,601
Average per day (Mcf)		8,076		7,795		8,100		225		238		317		8,301		8,033		8,417
Net Profits Interests
Oil—Sales (Bbls)		85,017		82,745		76,959		53,232		62,933		86,260		138,249		145,678		163,219
Average per day (Bbls)		233		227		210		146		172		236		379		399		446
Gas—Sales (Mcf)		2,630,283		2,530,916		2,659,139		18,511		21,291		30,120		2,648,794		2,552,207		2,689,259
Average per day (Mcf)		7,206		6,934		7,266		51		58		82		7,257		6,992		7,348
Average Sales Price
Oil (per Bbl)	$	22.87	$	24.22	$	26.41	$	22.10	$	25.26	$	27.85	$	22.31	$	24.99	$	27.49
Gas (per Mcf)	$	2.80	$	5.14	$	3.36	$	2.48	$	3.31	$	2.28	$	2.79	$	5.09	$	3.32

Nonproducing Acreage

The underlying nonproducing royalties contain approximately 200,000 gross (approximately 3,000 net) acres in Texas, Oklahoma and New Mexico which were nonproducing at the date of the trust’s creation. XTO Energy is the owner of underlying mineral interests in the majority of this acreage. The trust is entitled to 10% of oil and gas production attributable to the underlying mineral properties, but is not entitled to delay rental payments or lease bonuses. There has been no significant development of such nonproducing acreage since the trust’s creation. Included in the December 2002 distribution to unitholders was $477,000, or approximately $0.08 per unit, related to a one-time correction of the trust’s interest in these properties.

Pricing and Sales Information

Oil and gas are generally sold from the underlying properties at market-sensitive prices. The majority of sales from the underlying working interest properties are to major oil and gas companies. Information about purchasers of oil and gas from royalty properties is generally not provided by operators to XTO Energy as a royalty owner, or to the trust.

Oil and Natural Gas Reserves

General

Miller and Lents, Ltd., independent petroleum engineers, has estimated oil and gas reserves attributable to the underlying properties as of December 31, 2002, 2001, 2000 and 1999. The estimated reserves for the underlying properties are then used by XTO Energy to calculate the estimated oil and gas reserves attributable to

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the net profits interests. Numerous uncertainties are inherent in estimating reserve volumes and values, and such estimates are subject to change as additional information becomes available. The reserves actually recovered and the timing of production of these reserves may be substantially different from the original estimates.

Reserve quantities and revenues for the net profits interests were estimated from projections of reserves and revenues attributable to the combined interests of the trust and XTO Energy in the subject properties. Since the trust has defined net profits interests, the trust does not own a specific percentage of the oil and gas reserve quantities. Accordingly, reserves allocated to the trust pertaining to its 75% net profits interests in the working interest properties have effectively been reduced to reflect recovery of the trust’s 75% portion of applicable production and development costs. Because trust reserve quantities are determined using an allocation formula, any fluctuations in actual or assumed prices or costs will result in revisions to the estimated reserve quantities allocated to the net profits interests.

The standardized measure of discounted future net cash flows and changes in such discounted cash flows as presented below are prepared using assumptions required by the Financial Accounting Standards Board. Such assumptions include the use of year-end prices for oil and gas and year-end costs for estimated future development and production expenditures to produce the proved reserves. Because natural gas prices are influenced by seasonal demand, use of year-end prices, as required by the Financial Accounting Standards Board, may not be the most representative in estimating future revenues or reserve data. Future net cash flows are discounted at an annual rate of 10%. No provision is included for federal income taxes since future net cash flows are not subject to taxation at the trust level.

Year-end oil prices used to determine the standardized measure were based on a West Texas Intermediate crude oil posted price of $28.00 per Bbl in 2002, $16.75 per Bbl in 2001, $23.75 per Bbl in 2000 and $22.75 per Bbl in 1999. The year-end weighted average realized gas prices used to determine the standardized measure were $4.06 per Mcf in 2002, $2.28 per Mcf in 2001, $9.48 per Mcf in 2000 and $2.19 per Mcf in 1999.

Proved Reserves

	Net Profits Interests
(in thousands)	90% Net Profits Interests				75% Net Profits Interests				Total				Underlying Properties
	Oil (Bbls)		Gas (Mcf)		Oil (Bbls)		Gas (Mcf)		Oil (Bbls)		Gas (Mcf)		Oil (Bbls)		Gas (Mcf)
Balance, December 31, 1999	719.1		34,924.8		1,479.0		588.5		2,198.1		35,513.3		4,460.1		40,598.4
Extensions, discoveries and other additions	3.2		77.1		-0-		-0-		3.2		77.1		3.5		85.7
Revisions of prior estimates	32.7		1,864.4		33.2		14.0		65.9		1,878.4		123.5		1,773.5
Production	(77.0	)	(2,659.1	)	(86.2	)	(30.1	)	(163.2	)	(2,689.2	)	(344.1	)	(3,080.6	)
Balance, December 31, 2000	678.0		34,207.2		1,426.0		572.4		2,104.0		34,779.6		4,243.0		39,377.0
Extensions, discoveries and other additions	12.3		247.8		-0-		-0-		12.3		247.8		13.7		274.8
Revisions of prior estimates	6.9		(486.5	)	(678.2	)	(282.9	)	(671.3	)	(769.4	)	(483.6	)	(713.2	)
Production	(82.8	)	(2,530.9	)	(62.9	)	(21.3	)	(145.7	)	(2,552.2	)	(350.7	)	(2,932.2	)
Balance, December 31, 2001	614.4		31,437.6		684.9		268.2		1,299.3		31,705.8		3,422.4		36,006.4
Extensions, discoveries and other additions	11.5		48.3		-0-		-0-		11.5		48.3		12.8		53.7
Revisions of prior estimates	104.0		1,755.3		439.3		231.0		543.3		1,986.3		560.7		2,266.6
Production	(85.0	)	(2,630.3	)	(53.2	)	(18.5	)	(138.2	)	(2,648.8	)	(339.0	)	(3,029.9	)
Balance, December 31, 2002	644.9		30,610.9		1,071.0		480.7		1,715.9		31,091.6		3,656.9		35,296.8

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Revisions of prior estimates of the 75% net profits interests’ proved reserves and the underlying properties’ proved oil reserves in each of the years above were primarily the result of changes in the year-end oil price used in estimating proved reserves. During 2002 and 2000, upward revisions of the 90% net profits interests’ proved gas reserves were primarily because of lower than anticipated production declines. Downward revisions of the 90% net profits interests’ proved reserves in 2001 were primarily because of significantly lower year-end prices. Higher upward and downward revisions for the net profits interests as compared to underlying properties in 2001 and 2000 were caused by changes in the year-end gas price which resulted in increased reserves allocated to or from the trust. See “General” above.

Proved Developed Reserves

	Net Profits Interests
(in thousands)	90% Net Profits Interests		75% Net Profits Interests		Total		Underlying Properties
	Oil (Bbls)	Gas (Mcf)	Oil (Bbls)	Gas (Mcf)	Oil (Bbls)	Gas (Mcf)	Oil (Bbls)	Gas (Mcf)
December 31, 1999	715.7	33,036.5	1,375.0	570.3	2,090.7	33,606.8	4,245.6	38,463.3
December 31, 2000	675.0	32,371.1	1,317.8	553.5	1,992.8	32,924.6	4,028.8	37,300.0
December 31, 2001	611.4	29,608.5	602.0	253.7	1,213.4	29,862.2	3,208.3	33,937.3
December 31, 2002	642.4	29,330.7	1,071.0	480.7	1,713.4	29,811.4	3,654.1	33,874.4

Standardized Measure of Discounted Future Net Cash Flows from Proved Reserves

(in thousands)	90% Net Profits Interests									75% Net Profits Interests									Total
	December 31									December 31									December 31
	2002			2001			2000			2002			2001			2000			2002			2001			2000
Net Profits Interests
Future cash inflows	$	145,445		$	87,042		$	347,874		$	32,474		$	12,275		$	40,146		$	177,919		$	99,317		$	388,020
Future production taxes		(11,596	)		(6,945	)		(28,042	)		(2,212	)		(831	)		(2,786	)		(13,808	)		(7,776	)		(30,828	)
Future net cash flows		133,849			80,097			319,832			30,262			11,444			37,360			164,111			91,541			357,192
10% discount factor		(69,912	)		(42,004	)		(169,073	)		(14,208	)		(5,493	)		(18,692	)		(84,120	)		(47,497	)		(187,765	)
Standardized measure	$	63,937		$	38,093		$	150,759		$	16,054		$	5,951		$	18,668		$	79,991		$	44,044		$	169,427
Underlying Properties
Future cash inflows																			$	250,219		$	145,759		$	484,675
Future costs:
Production																				(61,148	)		(40,984	)		(78,973	)
Development																				-0-			(520	)		(520	)
Future net cash flows																				189,071			104,255			405,182
10% discount factor																				(96,624	)		(53,994	)		(212,781	)
Standardized measure																			$	92,447		$	50,261		$	192,401

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

(in thousands)	90% Net Profits Interests									75% Net Profits Interests									Total
	2002			2001			2000			2002			2001			2000			2002			2001			2000
Net Profits Interests
Standardized measure, January 1	$	38,093		$	150,759		$	43,578		$	5,951		$	18,668		$	17,048		$	44,044		$	169,427		$	60,626
Extensions, discoveries and other additions		327			507			461			-0-			-0-			-0-			327			507			461
Accretion of discount		3,238			12,702			3,683			512			1,614			1,476			3,750			14,316			5,159
Revisions of prior estimates, changes in price and other		30,092			(113,093	)		112,338			10,828			(12,724	)		2,504			40,920			(125,817	)		114,842
Net profits income		(7,813	)		(12,782	)		(9,301	)		(1,237	)		(1,607	)		(2,360	)		(9,050	)		(14,389	)		(11,661	)
Standardized measure, December 31	$	63,937		$	38,093		$	150,759		$	16,054		$	5,951		$	18,668		$	79,991		$	44,044		$	169,427
Underlying Properties
Standardized measure, January 1																			$	50,261		$	192,401		$	71,821
Revisions:
Prices and costs																				41,715			(140,000	)		122,144
Quantity estimates																				6,312			(1,581	)		7,162
Accretion of discount																				4,280			16,265			6,060
Future development costs																				(101	)		(1,091	)		(738	)
Other																				(53	)		49			(1,079	)
Net revisions																				52,153			(126,358	)		133,549
Extensions, additions and discoveries																				363			563			512
Production																				(10,902	)		(17,479	)		(14,220	)
Development costs																				572			1,134			739
Net change																				42,186			(142,140	)		120,580
Standardized measure, December 31																			$	92,447		$	50,261		$	192,401

Discounted Present Value of the Coal Seam Tax Credit

The standardized measure above does not include the effects of the coal seam tax credit since the trust is not a taxable entity. The following table summarizes the estimated coal seam tax credit attributable to the 90% net profits interests at December 31, 2001 and 2000. Such estimates are based on projected coal seam gas production through 2002 (after which date the tax credit is no longer available) as estimated by independent engineers. The estimates are also based on the estimated Btu content and the coal seam tax credit of $1.08 per MMBtu at December 31, 2001 and $1.06 per MMBtu at December 31, 2000. See “Regulation—Coal Seam Tax Credit.”

	December 31,
(in thousands)	2002(a)	2001		2000
Undiscounted	—	$	922	$	1,225
Discounted present value at 10%	—	$	880	$	1,120

(a) The coal seam tax credit is not available for production after December 31, 2002.

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Reversion Agreement

Certain of the underlying royalties are subject to a reversion agreement between XTO Energy and a third party. The agreement calls for XTO Energy to transfer 25% of its interest in those properties to the third party when amounts received by XTO Energy from the underlying properties subject to the agreement equal the purchase price of the properties plus a 1% per month return on the unrecouped purchase price, known as payout. If payout were to occur and the 25% interest were to be transferred to the third party, the amounts payable to the trust would be proportionately reduced. Based on 2002 prices and levels of production, XTO Energy has informed the trustee that payout is not projected to occur for more than 20 years. Unless higher prices and production are sustained for several years, this reversion agreement is not expected to have a material impact on the trust.

Regulation

Natural Gas Regulation

The interstate transportation and sale for resale of natural gas is subject to federal regulation, including transportation rates charged and various other matters, by the Federal Energy Regulatory Commission (FERC). Federal price controls on wellhead sales of domestic natural gas terminated on January 1, 1993. While natural gas prices are currently unregulated, Congress historically has been active in the area of natural gas regulation. It is impossible to predict whether new legislation to regulate natural gas might be proposed, what proposals, if any, might actually be enacted by Congress or the various state legislatures, and what effect, if any, such proposals might have on the operations of the underlying properties.

State Regulation

The various states regulate the production and sale of oil and natural gas, including imposing requirements for obtaining drilling permits, the method of developing new fields, the spacing and operation of wells and the prevention of waste of oil and gas resources. The rates of production may be regulated and the maximum daily production allowables from both oil and gas wells may be established on a market demand or conservation basis, or both.

Coal Seam Tax Credit

The trust receives net profits income from coal seam gas wells. Under Section 29 of the Internal Revenue Code, coal seam gas produced through the year 2002 from wells drilled after December 31, 1979 and prior to January 1, 1993 qualifies for the federal income tax credit for producing nonconventional fuels. This tax credit for 2002 was approximately $1.10 per MMBtu. This credit, calculated based on the unitholder’s pro rata share of qualifying production, may not reduce the unitholder’s regular tax liability (after the foreign tax credit and certain other nonrefundable credits) below his tentative minimum tax. Any part of the Section 29 credit not allowed for the tax year solely because of this limitation is subject to certain carryover provisions.

Congress has considered extending this credit beyond the December 31, 2002 expiration date, and the creation of similar new tax credits. Unless new legislation is passed, extending this credit on existing eligible production or allowing for credits on new production, there will be no further benefit on production past the year 2002.

Other Regulation

The petroleum industry is also subject to compliance with various other federal, state and local regulations and laws, including, but not limited to, regulations and laws relating to environmental protection, occupational safety, resource conservation and equal employment opportunity. XTO Energy has advised the trustee that it does not believe that compliance with these laws will have any material adverse effect upon the unitholders.

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Item 3.    Legal Proceedings

Certain of the trust properties are involved in various lawsuits and certain governmental proceedings arising in the ordinary course of business. XTO Energy has advised the trustee that it does not believe that the ultimate resolution of these claims will have a material effect on trust annual distributable income, financial position or liquidity.

Item 4.    Submission of Matters to a Vote of Security Holders

No matters were submitted to a vote of unitholders during 2002.

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PART II

Item 5.    Market for Units of the Trust and Related Security Holder Matters

The section entitled “Units of Beneficial Interest” on page 1 of the trust’s annual report to unitholders for the year ended December 31, 2002 is incorporated herein by reference.

Item 6.    Selected Financial Data

	Year Ended December 31
	2002		2001		2000		1999		1998
Net Profits Income	$	9,049,271	$	14,389,316	$	11,660,510	$	6,691,336	$	7,079,632
Distributable Income		8,822,310		14,209,884		11,502,114		6,549,803		6,927,338
Distributable Income per Unit		1.470385		2.368314		1.917019		1.091635		1.154555
Distributions per Unit		1.470385		2.368314		1.917019		1.091635		1.154555
Total Assets at Year-End		27,805,823		29,747,914		31,806,794		33,919,338		36,554,480

Item 7.    Management’s Discussion and Analysis of Financial Condition and Results of Operations

The “Trustee’s Discussion and Analysis” of financial condition and results of operations for the three-year period ended December 31, 2002 on pages 6 through 8 of the trust’s annual report to unitholders for the year ended December 31, 2002 is incorporated herein by reference.

Liquidity and Capital Resources

The trust’s only cash requirement is the monthly distribution of its income to unitholders, which is funded by the monthly receipt of net profits income after payment of trust administration expenses. The trust is not liable for any production costs or liabilities attributable to the net profits interests. If at any time the trust receives net profits income in excess of the amount due, the trust is not obligated to return such overpayment, but future net profits income payable to the trust will be reduced by the overpayment, plus interest at the prime rate. The trust may borrow funds required to pay trust liabilities if fully repaid prior to further distributions to unitholders.

The trust does not have any transactions, arrangements or other relationships with unconsolidated entities or persons that could materially affect the trust’s liquidity or the availability of capital resources.

Contractual Obligations and Commitments

The trust had no obligations and commitments to make future contractual payments as of December 31, 2002, other than the December distribution payable to unitholders in January 2003, as reflected in the statement of assets, liabilities and trust corpus. The trust has not guaranteed the debt of any other party, nor does the trust have any other arrangements or relationships with other entities that could potentially result in unconsolidated debt. Additionally, the trust has no off balance sheet financing arrangements.

Related Party Transactions

The underlying properties are currently owned by XTO Energy. As of March 3, 2003, XTO Energy owned 1,360,000, or 22.7%, of the 6,000,000 outstanding units. XTO Energy deducts an overhead charge from monthly net proceeds as reimbursement for costs associated with monitoring the 75% net profits interests. As of December 31, 2002, this monthly charge was $23,470 ($17,603 net to the trust) and is subject to annual adjustment based on an oil and gas industry index. For further information regarding the trust’s relationship with XTO Energy, see Note 6 to Financial Statements in the trust’s Annual Report to unitholders for the year ended December 31, 2002.

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Critical Accounting Policies

The financial statements of the trust are significantly affected by its basis of accounting and estimates related to its oil and gas properties and proved reserves, as summarized below.

Basis of Accounting

The trust’s financial statements are prepared on a modified cash basis, which is a comprehensive basis of accounting other than generally accepted accounting principles. This method of accounting is consistent with reporting of taxable income to trust unitholders. The most significant differences between the trust’s financial statements and those prepared in accordance with generally accepted accounting principles are:

— Net profits income is recognized in the month received rather than accrued in the month of production.

— Expenses are recognized when paid rather than when incurred.

— Cash reserves may be established by the trustee for certain contingencies that would not be recorded under generally accepted accounting principles.

For further information regarding the trust’s basis of accounting, see Note 2 to Financial Statements in the trust’s Annual Report to unitholders for the year ended December 31, 2002.

All amounts included in the trust’s financial statements are based on cash amounts received or disbursed, or on the carrying value of the net profits interests, which was derived from the historical cost of the interests at the date of their transfer from XTO Energy, less accumulated amortization to date. Accordingly, there are no fair value estimates included in the financial statements based on either exchange or non-exchange trade values.

Oil and Gas Reserves

The trust’s proved oil and gas reserves are estimated by independent petroleum engineers. Reserve engineering is a subjective process that is dependent upon the quality of available data and the interpretation thereof. Estimates by different engineers often vary, sometimes significantly. In addition, physical factors such as the results of drilling, testing and production subsequent to the date of an estimate, as well as economic factors such as changes in product prices, may justify revision of such estimates. Because proved reserves are required to be estimated using prices at the date of the evaluation, estimated reserve quantities can be significantly impacted by changes in product prices. Accordingly, oil and gas quantities ultimately recovered and the timing of production may be substantially different from original estimates.

The standardized measure of discounted future net cash flows and changes in such cash flows, as reported in Item 2 of the trust’s Annual Report on Form 10-K, is prepared using assumptions required by the Financial Accounting Standards Board and the Securities and Exchange Commission. Such assumptions include using year-end oil and gas prices and year-end costs for estimated future development and production expenditures. Discounted future net cash flows are calculated using a 10% rate. Changes in any of these assumptions, including consideration of other factors, could have a significant impact on the standardized measure. Accordingly, the standardized measure does not represent XTO Energy’s or the trustee’s estimated current market value of proved reserves.

Forward-Looking Statements

Certain information included in this annual report and other materials filed, or to be filed, by the trust with the Securities and Exchange Commission (as well as information included in oral statements or other written statements made or to be made by XTO Energy or the trustee) contain forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended, and Section 27A of the Securities Act of 1933, as amended, relating to the trust operations of the underlying properties and the oil and gas industry.

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Such forward-looking statements may concern, among other things, development activities, maintenance projects, development, production and other costs, oil and gas prices, pricing differentials, proved reserves, production levels, litigation, regulatory matters and competition. Such forward-looking statements are based on XTO Energy’s current plans, expectations, assumptions, projections and estimates and are identified by words such as “expects,” “intends,” “plans,” “projects,” “anticipates,” “predicts,” “believes,” “goals,” “estimates,” “should,” “could,” and similar words that convey the uncertainty of future events. These statements are not guarantees of future performance and involve certain risks, uncertainties and assumptions that are difficult to predict. Therefore, actual results may differ materially from expectations, estimates or assumptions expressed in, implied in, or forecasted in such forward-looking statements. Some of the risk factors that could cause actual results to differ materially are discussed below.

Oil and Gas Price Fluctuations.    The trust’s monthly cash distributions are highly dependent upon the prices realized from the sale of gas and, to a lesser extent, oil. Oil and gas prices can fluctuate widely on a month-to-month basis in response to a variety of factors that are beyond the control of the trust and XTO Energy. Factors that contribute to price fluctuations include instability in oil-producing regions, worldwide economic conditions, weather conditions, the supply and price of foreign oil and gas, consumer demand, and the price and availability of alternative fuels. Moreover, government regulations, such as regulation of natural gas transportation and price controls, can affect product prices in the long term. Lower oil and gas prices may reduce the amount of oil and gas that is economic to produce and will reduce net profits available to the trust. The volatility of energy prices reduces the predictability of future cash distributions to trust unitholders.

Increased Production and Development Costs.    Production and development costs on the 75% net profits interests properties are deducted in the calculation of the trust’s share of net proceeds. Accordingly, higher or lower production and development costs, without concurrent increases in revenue, will directly decrease or increase the amount received by the trust for its 75% net profits interests. If development and production costs of the 75% net profits interests located in a particular state exceed the production proceeds from the properties, the trust will not receive net proceeds for those properties until future proceeds from production in that state exceed the total of the excess costs plus accrued interest during the deficit period. Development activities may not generate sufficient additional revenue to repay the costs.

Reserve Estimates.    Estimating reserves is inherently uncertain. Petroleum engineers consider many factors and make assumptions in estimating reserves and future net cash flows. Lower oil and gas prices generally cause lower estimates of proved reserves. Ultimately, actual production, revenues and expenditures for the underlying properties will vary from estimates and those variations could be material. The trust’s reserve quantities are based on estimates of reserves for the underlying properties. The method of allocating a portion of those reserves to the trust is complicated because the trust holds an interest in net profits and does not own a specific percentage of the oil and gas reserves.

Operating Risks.    The occurrence of drilling, production or transportation accidents at any of the underlying working interest properties will reduce trust distributions by the amount of uninsured costs. These accidents may result in personal injuries, property damage, damage to productive formations or equipment and environmental damages. Any uninsured costs would be deducted as production costs in calculating net proceeds payable to the trust.

No Control Over the Operation or Development of Underlying Properties.    Because XTO Energy does not operate most of the underlying properties, it is unable to significantly influence the operations or future development of the underlying properties. Neither the trustee nor the trust unitholders can influence or control the operation or future development of the underlying properties. The current operators of the underlying properties are under no obligation to continue operating the properties. Neither the trustee nor trust unitholders have the right to replace an operator.

Trust’s Assets are Depleting Assets.    The net proceeds payable to the trust are derived from the sale of depleting assets. Accordingly, the portion of the distributions to trust unitholders attributable to depletion may be

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considered a return of capital. The reduction in proved reserve quantities is a common measure of the depletion. Future maintenance and development projects on the underlying properties will affect the quantity of proved reserves. The timing and size of these projects will depend on the market prices of oil and gas. If operators of the properties do not implement additional maintenance and development projects, the future rate of production decline of proved reserves may be higher than the rate currently expected by XTO Energy.

Item 7a.    Quantitative and Qualitative Disclosures about Market Risk

The only assets of and sources of income to the trust are the net profits interests, which generally entitle the trust to receive a share of the net profits from oil and gas production from the underlying properties. Consequently, the trust is exposed to market risk from fluctuations in oil and gas prices. The trust is a passive entity and, other than the trust’s ability to periodically borrow money as necessary to pay expenses, liabilities and obligations of the trust that cannot be paid out of cash held by the trust, the trust is prohibited from engaging in borrowing transactions. The amount of any such borrowings is unlikely to be material to the trust. In addition, the trustee is prohibited by the trust indenture from engaging in any business activity or causing the trust to enter into any investments other than investing cash on hand in specific short-term cash investments. Therefore, the trust cannot hold any derivative financial instruments. As a result of the limited nature of its borrowing and investing activities, the trust is not subject to any material interest rate market risk. Additionally, any gains or losses from any hedging activities conducted by XTO Energy are specifically excluded from the calculation of net proceeds due the trust under the forms of the conveyances. The trust does not engage in transactions in foreign currencies which could expose the trust to any foreign currency related market risk.

Item 8.    Financial Statements and Supplementary Data

The financial statements of the trust and the notes thereto, together with the related reports of KPMG LLP dated March 14, 2003 and Arthur Andersen LLP dated March 19, 2002, appearing on pages 9 through 12 of the trust’s annual report to unitholders for the year ended December 31, 2002 are incorporated herein by reference.

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

On June 25, 2002, the trustee appointed KPMG LLP as independent auditors for fiscal year 2002 to replace Arthur Andersen LLP, effective with such appointment. Information regarding this change in independent auditors is included in the trust’s current report on Form 8-K dated June 25, 2002.

There have been no other changes in accountants and there have been no disagreements with accountants on any matter of accounting principles or practices or financial statement disclosures during the two years ended December 31, 2002.

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PART III

Item 10.    Directors and Executive Officers of the Registrant

The trust has no directors or executive officers. The trustee is a corporate trustee which may be removed, with or without cause, by the affirmative vote of the holders of a majority of all the units then outstanding.

Section 16(a) of the Securities Exchange Act of 1934 requires that beneficial owners of more than 10% of the registrant’s equity securities file initial reports of beneficial ownership and reports of changes in beneficial ownership with the Securities and Exchange Commission and the New York Stock Exchange. Copies of the reports must be provided to the trust. To the trustee’s knowledge, based solely on the information furnished to the trust, the trust is unaware of any person that failed to file on a timely basis reports required by Section 16(a) filing requirements with respect to the trust units of beneficial interest during and for the year ended December 31, 2002.

Item 11.    Executive Compensation

The trustee received the following annual compensation from 2000 through 2002 as specified in the trust indenture:

Name and Principal Position	Year	Other Annual Compensation (1)
Bank of America, N.A., Trustee	2002	$4,525
	2001	7,195
	2000	5,830

(1) Under the trust indenture, the trustee is entitled to an administrative fee of: (i) 1/20 of 1% of the first $100 million of the annual gross revenue of the trust, and 1/30 of 1% of the annual gross revenue of the trust in excess of $100 million, and (ii) trustee’s standard hourly rates for time in excess of 300 hours annually.

Item 12.    Security Ownership of Certain Beneficial Owners and Management

The trust has no equity compensation plans.

(a)  Security Ownership of Certain Beneficial Owners.    The following table sets forth as of March 3, 2003 information with respect to each person known to the trustee to beneficially own more than 5% of the outstanding units of the trust:

Name and Address	Amount and Nature of Beneficial Ownership	Percent of Class
XTO Energy Inc. 810 Houston Street Fort Worth, TX 76102	1,360,000 units (1)	22.7%

(1) XTO Energy has the sole power to vote and dispose of these units.

(b)  Security Ownership of Management.    The trust has no directors or executive officers. As of February 26, 2003, Bank of America, N.A. owned, in various fiduciary capacities, 80,760 units with a shared right to vote 46,088 of these units and no right to vote 34,672 of these units. Bank of America, N.A. disclaims any beneficial interests in these units. The number of units reflected in this paragraph includes units held by all branches of Bank of America, N.A.

(c)  Changes in Control.    The trustee knows of no arrangements which may subsequently result in a change in control of the trust.

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Item 13.    Certain Relationships and Related Transactions

In computing net profits income paid to the trust for the 75% net profits interests, XTO Energy deducts an overhead charge as reimbursement for costs associated with monitoring these interests. This charge at December 31, 2002 was $23,470 per month, or $281,640 annually (net to the trust of $17,603 per month or $211,236 annually), and is subject to annual adjustment based on an oil and gas industry index.

See Item 11 for the remuneration received by the trustee from 2000 through 2002 and Item 12(b) for information concerning units owned by the trustee, Bank of America, N.A., in various fiduciary capacities.

Item 14.    Controls and Procedures

Within the 90 days prior to the date of this report, the trustee carried out an evaluation of the effectiveness of the design and operation of the trust’s disclosure controls and procedures pursuant to Exchange Act Rule 13a-14. Based upon that evaluation, the trustee concluded that the trust’s disclosure controls and procedures are effective in timely alerting the trustee to material information relating to the trust required to be included in the trust’s periodic filings with the Securities and Exchange Commission. In its evaluation of disclosure controls and procedures, the trustee has relied, to the extent considered reasonable, on information provided by XTO Energy. No significant changes in the trust’s internal controls or other factors that could affect these controls have occurred subsequent to the date of such evaluation.

PART IV

Item 15.    Exhibits, Financial Statement Schedules and Reports on Form 8-K

(a) The following documents are filed as a part of this report:

1. Financial Statements (incorporated by reference in Item 8 of this report)

Independent Auditors’ Reports

Statements of Assets, Liabilities and Trust Corpus at December 31, 2002 and 2001

Statements of Distributable Income for the years ended December 31, 2002, 2001 and 2000

Statements of Changes in Trust Corpus for the years ended December 31, 2002, 2001 and 2000

Notes to Financial Statements

2. Financial Statement Schedules

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

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3. Exhibits

(4)(a)	Cross Timbers Royalty Trust Indenture amended and restated on January 13, 1992 by NationsBank, N.A. (now Bank of America, N.A.), as trustee, heretofore filed as Exhibit 3.1 to the trust’s Registration Statement No. 33-44385 filed with the Securities and Exchange Commission on February 19, 1992, is incorporated herein by reference.
(b)	Net Overriding Royalty Conveyance (Cross Timbers Royalty Trust, 90%—Texas) from South Timbers Limited Partnership, West Timbers Limited Partnership, North Timbers Limited Partnership, East Timbers Limited Partnership, Hickory Timbers Limited Partnership, and Cross Timbers Partners, L.P. (predecessors of XTO Energy Inc.) to NCNB Texas National Bank (now Bank of America, N.A.), as trustee, dated February 12, 1991 (without Schedules A and B), heretofore filed as Exhibit 10.1 to the trust’s Registration Statement No. 33-44385 filed with the Securities and Exchange Commission on February 19, 1992, is incorporated herein by reference.
(c)	Correction to Net Overriding Royalty Conveyance (Cross Timbers Royalty Trust, 90%—Texas) from South Timbers Limited Partnership, West Timbers Limited Partnership, North Timbers Limited Partnership, East Timbers Limited Partnership, Hickory Timbers Limited Partnership, and Cross Timbers Partners, L.P. (predecessors of XTO Energy Inc.) to NCNB Texas National Bank (now Bank of America, N.A.), as trustee, dated September 23, 1991 (without Schedules A and B), heretofore filed as Exhibit 10.2 to the trust’s Registration Statement No. 33-44385 filed with the Securities and Exchange Commission on February 19, 1992, is incorporated herein by reference.
(d)	Net Overriding Royalty Conveyance (Cross Timbers Royalty Trust, 75%—Texas) from South Timbers Limited Partnership, West Timbers Limited Partnership, North Timbers Limited Partnership, East Timbers Limited Partnership, Hickory Timbers Limited Partnership, and Cross Timbers Partners, L.P. (predecessors of XTO Energy Inc.) to NCNB Texas National Bank (now Bank of America, N.A.), as trustee, dated February 12, 1991 (without Schedules A and B), heretofore filed as Exhibit 10.5 to the trust’s Registration Statement No. 33-44385 filed with the Securities and Exchange Commission on February 19, 1992, is incorporated herein by reference.
(13)	Cross Timbers Royalty Trust Annual Report to unitholders for the year ended December 31, 2002
(23.1)	Consent of KPMG LLP
(23.2)	Notice Regarding Consent of Arthur Andersen LLP
(23.3)	Consent of Miller and Lents, Ltd.
(99.1)	Trustee Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

Copies of the above Exhibits are available to any unitholder, at the actual cost of reproduction, upon written request to the trustee, Bank of America, N.A., P.O. Box 830650, Dallas, Texas 75283-0650.

(b) Reports on Form 8-K

During the last quarter of the trust’s fiscal year ended December 31, 2002, there were no reports filed on Form 8-K by the trust with the Securities and Exchange Commission.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this Report to be signed on its behalf by the undersigned thereunto duly authorized.

	CROSS TIMBERS ROYALTY TRUST By BANK OF AMERICA, N.A., TRUSTEE
	By:	/s/    NANCY G. WILLIS
		Nancy G. Willis Assistant Vice President
	XTO ENERGY INC.
Date: March 31, 2003	By:	/s/    LOUIS G. BALDWIN
		Louis G. Baldwin Executive Vice President and Chief Financial Officer

(The trust has no directors or executive officers.)

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CERTIFICATIONS

I, Nancy G. Willis, certify that:

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

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

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

4. I am responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14), or for causing such procedures to be established and maintained, for the registrant and I have:

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

b) evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the “Evaluation Date”); and

c) presented in this annual report my conclusions about the effectiveness of the disclosure controls and procedures based on my evaluation as of the Evaluation Date;

5. I have disclosed, based on my most recent evaluation, to the registrant’s auditors:

a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and

b) any fraud, whether or not material, that involves persons who have a significant role in the registrant’s internal controls; and

6. I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of my most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

In giving the certifications in paragraphs 4, 5 and 6 above, I have relied to the extent I consider reasonable on information provided to me by XTO Energy Inc.

Date: March 31, 2003

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

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