-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, RzJBxn8wTTo3pFOPI8S7IZXCJhQSwawu7JP39vFcGOlpb7KrklByE5SGaSCdtKHf i2mp4TtcBNf2H6cstAFPrg== 0000912057-02-011962.txt : 20020415 0000912057-02-011962.hdr.sgml : 20020415 ACCESSION NUMBER: 0000912057-02-011962 CONFORMED SUBMISSION TYPE: 10-K405 PUBLIC DOCUMENT COUNT: 5 CONFORMED PERIOD OF REPORT: 20011231 FILED AS OF DATE: 20020327 FILER: COMPANY DATA: COMPANY CONFORMED NAME: HUGOTON ROYALTY TRUST CENTRAL INDEX KEY: 0000862022 STANDARD INDUSTRIAL CLASSIFICATION: OIL ROYALTY TRADERS [6792] IRS NUMBER: 586379215 STATE OF INCORPORATION: TX FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K405 SEC ACT: 1934 Act SEC FILE NUMBER: 001-10476 FILM NUMBER: 02589088 BUSINESS ADDRESS: STREET 1: C/O NATIONS BANK, N.A. TRUSTEE STREET 2: 901 MAIN ST., 17TH FLOOR CITY: DALLAS STATE: TX ZIP: 75202 BUSINESS PHONE: 2145082400 10-K405 1 a2073906z10-k405.htm 10-K405
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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, 2001

Commission file number 1-10476

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

Texas		58-6379215
(State or other jurisdiction of		(I.R.S. Employer
incorporation or organization)		Identification No.)
Bank of America, N.A.		75283-0650
Trustee		(Zip Code)
P.O. Box 830650
Dallas, Texas
(Address of principal executive offices)

Registrant's telephone number including area code: (877) 228-5083

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]

At March 1, 2002, there were 40,000,000 units of beneficial interest of the trust outstanding. The aggregate market value of the units (based on the closing price on the New York Stock Exchange on March 1, 2002) held by non-affiliates of the registrant on that date was approximately $105.9 million.

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:

2001 Annual Report to Unitholders—Part II

PART I

Item 1. Business

Hugoton Royalty Trust is an express trust created under the laws of Texas pursuant to the Hugoton Royalty Trust Indenture entered into on December 1, 1998 between XTO Energy Inc., as grantor, and NationsBank, N.A., as trustee. Bank of America, N.A., successor to NationsBank, N.A., is now the trustee of the trust. The principal office of the trust is located at 901 Main Street, Dallas, Texas 75202 (telephone number 877-228-5083).

Effective December 1, 1998, XTO Energy (formerly known as Cross Timbers Oil Company) conveyed to the trust 80% net profits interests in certain predominantly natural gas producing working interest properties in Kansas, Oklahoma and Wyoming under three separate conveyances. In exchange for these net profits interest conveyances to the trust, 40 million units of beneficial interest were issued to XTO Energy. In April and May 1999, XTO Energy sold a total of 17 million units in the trust's initial public offering. In 1999 and 2000, XTO Energy also sold 1.3 million trust units to certain of its officers. The trust did not receive any proceeds from these sales of trust units. As of March 1, 2002, XTO Energy owned 21,705,893 units in the trust. Units are listed and traded on the New York Stock Exchange under the symbol "HGT."

The net profits interests entitle the trust to receive 80% of net proceeds from the sale of oil and gas from the underlying properties. Each month XTO Energy determines the amount of cash received from the sale of production and deducts property and production taxes, development and production costs and overhead. For trust distributions declared through March 2000, net proceeds from the sale of gas related to those distributions were contractually required to be computed differently. Net proceeds for this period were computed monthly based on the greater of either a realized price of $2.00 per Mcf or the actual price received by XTO Energy for natural gas sold.

Net proceeds payable to the trust depend upon production quantities, sales prices of oil and gas and costs to develop and produce oil and gas in the prior month. If monthly costs exceed revenues for any of the three conveyances (one for each of the states of Kansas, Oklahoma, and Wyoming), such excess costs must be recovered, with accrued interest, from future net proceeds of that conveyance and cannot reduce net proceeds from other conveyances.

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.

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. See Item 2., "Pricing and Sales Information."

Net profits income received by the trust on or before the last business day of the month is related to net proceeds received by XTO Energy in the preceding month, and generally represents receipts attributable to oil and gas production two months prior. The amount to be distributed to unitholders each month by the trustee is determined by:

Adding—

(1): net profits income received,
(2): interest income and any other cash receipts and
(3): cash available as a result of reduction of cash reserves, then

Subtracting the sum of—

(1): liabilities paid and
(2): the reduction in cash available related to establishment of or increase in any cash reserve.

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

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

The trustee's function is to collect the net profits income from the net profits interests, to pay all trust expenses, and pay the monthly distribution amount to unitholders. The trustee's powers are specified by the terms of the trust 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 94% of the net profits income received by the trust during 2001, as well as 94% of the estimated proved reserves of the net profits interests at December 31, 2001 (based on estimated future net revenues 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 generally 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 assets, with the exception of certain short-term investments as specified under Item 1. The trustee may sell or otherwise dispose of all or any part of the net profits interests if approved by at least 80% of the unitholders, or upon termination of the trust. Otherwise, the trust may only sell up to 1% of the value of the net profits interests in any calendar year, pursuant to notice from XTO Energy of its desire to sell the related underlying properties. Any such sale must be for cash with the proceeds promptly distributed to the unitholders. The underlying properties are predominantly natural gas producing leases located in the states of Kansas, Oklahoma and Wyoming. The principal productive areas are the Hugoton area, Anadarko Basin and Green River Basin.

Hugoton Area

Natural gas was discovered in the Hugoton area in 1922. With an estimated five million productive acres covering parts of Texas, Oklahoma and Kansas, the Hugoton area is the largest natural gas producing area in North America. More than 64 trillion cubic feet of natural gas have been produced from the Hugoton area. During 2001, sales volumes from the underlying properties in the Hugoton area averaged approximately 30,800 Mcf of gas per day and 72 Bbls of oil per day.

Most of the production from the underlying properties in the Hugoton area is from the Chase formation, at depths of 2,700 to 2,900 feet. Although increased density drilling was ultimately not approved by the Oklahoma legislature, regulations were amended in July 1998 to increase allowable production in the Oklahoma panhandle from 150,000 Mcf per day to 450,000 Mcf per day which lifted curtailment in this area. XTO Energy also plans to develop other formations that underlie the 79,500 net acres held by production by the Chase formation wells, including the Council Grove between 2,950 and 3,400 feet, the Morrow between 6,000 and 6,300 feet, the Chester between 6,350 and 6,700 feet and the St. Louis between 7,500 and 8,000 feet. XTO Energy has participated in 3-D seismic shoots covering 30,000 acres of XTO Energy's net acreage position beneath the Chase formation. Test wells were drilled to delineate the Council Grove formation in 1999, 2000 and 2001.

During 2001, development of the Hugoton area included successful recompletions to the Towanda Formation. XTO Energy also embarked on a pilot project to test new restimulation techniques in the Chase intervals. XTO Energy completed 27 of these restimulations in 2001. During 2002, XTO Energy plans to perform seven Towanda completions and 46 Chase restimulations.

XTO Energy's future development plans for the underlying properties in the Hugoton area include:

•: additional compression to lower line pressures,
•: pumping unit installations,
•: opening new producing zones of existing wells,
•: drilling additional wells, and
•: drilling deeper in existing wells to new producing zones.

XTO Energy delivers most of its Hugoton gas production to a gathering and processing system operated by a subsidiary. This system collects approximately 75% of its throughput from underlying properties, which, in recent months, has been approximately 24,000 Mcf per day from 270 wells. The gathering subsidiary purchases the gas from XTO Energy at the wellhead, gathers and transports the gas to its plant, and treats and processes the gas at the plant. The gathering subsidiary pays XTO Energy for wellhead volumes at a price of 80% to 85% of the residue price received upon sale to XTO Energy's marketing affiliate. Under long-term contracts, the gathering subsidiary sells residue volumes to XTO Energy's marketing affiliate at a price equal to the average price of several published indices and is reduced by any pipeline access fees incurred by the marketing affiliate, but is not reduced by any marketing fees. Pipeline access fees currently are approximately $0.02 per Mcf.

Other Hugoton gas production is delivered under a third party contract. Under the contract, XTO Energy receives 74.5% of the net proceeds received from the sale of the residue gas and liquids.

Anadarko Basin

Oil and gas were discovered in the Anadarko Basin of western Oklahoma in 1945. Daily sales volumes from the underlying properties in the Anadarko Basin averaged 44,500 Mcf and 946 Bbls in 2001. XTO Energy is one of the largest producers in the Ringwood, Northwest Okeene and Cheyenne Valley fields in Major County, the principal producing region of the underlying properties in the Anadarko Basin.

The fields in the Major County area are characterized by oil and gas production from a variety of structural and stratigraphic traps. Productive zones range from 6,500 to 9,400 feet and include the Oswego, Red Fork, Inola, Chester, Manning, Mississippian, Hunton and Arbuckle formations.

In Major and Woodward counties, the Mississippian (Osage), Chester and Red Fork formations were the primary drilling targets in 2001. In Major County, XTO Energy successfully drilled and completed 13 gross (10.5 net) wells. XTO Energy plans to drill up to six wells and perform up to 19 workovers in Major County during the next year. In Woodward County, the Chester Formation with its four separate producing intervals, was the primary target for 16 gross (13.5 net) wells successfully drilled and completed during 2001. During 2002, XTO Energy plans to drill up to 12 gross (8.3 net) wells and perform up to six workovers in Woodward County.

XTO Energy plans to further develop the underlying properties in the Major County area primarily through:

•: mechanical stimulation of existing wells,
•: opening new producing zones in existing wells,
•: deepening existing wells to new producing zones, and
•: drilling additional wells.

A gathering subsidiary of XTO Energy operates a 300-mile gathering system and pipeline in the Major County area. The gathering subsidiary and a third-party processor purchase natural gas produced at the wellhead from XTO Energy and other producers in the area under life-of-production contracts. The gathering subsidiary gathers and transports the gas to a third-party processor, which processes the gas and pays XTO Energy and other producers for at least 50% of the liquids processed. After the gas is processed, the gathering subsidiary transports the gas via a 26-mile pipeline to a connection with other pipelines. The gathering subsidiary sells the residue gas to the marketing subsidiary of XTO Energy based upon the average price of several published indices. The gathering subsidiary pays this price to XTO Energy less a compression and gathering fee of $0.315 per Mcf of residue gas. This gathering fee was previously approved by the Federal Energy Regulatory Commission when the gathering subsidiary was regulated. During 2001, the gathering system collected approximately 21,000 Mcf per day from over 400 wells, 70% of which XTO Energy operates. Estimated capacity of the gathering system is 40,000 Mcf per day. The gathering subsidiary also provides contract operating services to properties in Woodward County, collecting approximately 256,000 Mcf per month from 48 wells, for a historical average fee of approximately $0.125 per Mcf.

XTO Energy also sells gas to its marketing subsidiary, which then sells the gas to third parties. The price paid to XTO Energy is based upon the average price of several published indices, but does not include a deduction for any marketing fees. The price paid by the marketing affiliate includes a deduction for any transportation fees charged by the third party.

Green River Basin

The Green River Basin is located in southwestern Wyoming. Natural gas was discovered in the Fontenelle field of the Green River Basin in the early 1970s. The producing reservoirs are the Cretaceous-aged Frontier, Baxter and Dakota sandstones at depths ranging from 7,500 to 10,000 feet. In 2001, daily sales volumes from the underlying properties in the Fontenelle field averaged 24,900 Mcf of natural gas and 60 Bbls of oil.

During 1997, XTO Energy installed additional pipeline compression to lower overall field operating pressures and improve overall field performance. XTO Energy also completed an interconnect to another pipeline in the southeastern part of the Fontenelle field that added an additional market for gas.

XTO Energy drilled six gross (6.0 net) wells in the Fontenelle Unit in 2001, all of which were successfully completed. Drilling focused on continued 80-acre and 40-acre infill development of the Frontier sandstones. XTO Energy plans to perform up to six workovers in the Green River Basin during 2002.

Potential development activities for the underlying properties in this area include:

•: additional compression to lower line pressures,
•: opening new producing zones of existing wells,
•: deepening existing wells to new producing zones, and
•: drilling additional wells.

XTO Energy markets the gas produced from the Fontenelle Unit and nearby properties under three different marketing arrangements. Under the agreement covering 70% of the gas sold, XTO Energy compresses the gas on the lease, transports it off the lease and compresses the gas again prior to entry into the gas plant pipeline. The pipeline transports the gas 35 miles to the gas plant, where the gas is processed, then redelivered to XTO Energy and sold to XTO Energy's marketing subsidiary. The owner of the gas plant and related pipeline charges XTO Energy for operational fuel and processing. In 2001, the fuel charge was 0.02% of the volumes produced and the processing fee was $0.051 per MMBtu. The marketing subsidiary then sells the residue gas to third parties based upon a spot sales price and pays the net sales proceeds to XTO Energy. The marketing subsidiary does not receive a marketing fee. The gas not sold

under the above arrangement is sold either under a similar arrangement where the fee is $0.148 per MMBtu, or under a contract where XTO Energy directly sells the gas to a third party on the lease at an adjusted index price. Condensate is sold at the lease to an independent third party at market rates.

Producing Acreage and Well Counts

For the following data, "gross" refers to the total wells or acres on the underlying properties in which XTO Energy owns a working interest and "net" refers to gross wells or acres multiplied by the percentage working interest owned by XTO Energy. Although many of XTO Energy's wells produce both oil and gas, a well is categorized as an oil well or a gas well based upon the ratio of oil to natural gas production.

The underlying properties are interests in developed properties located primarily in gas producing regions of Kansas, Oklahoma and Wyoming. The following is a summary of the approximate producing acreage of the underlying properties at December 31, 2001. Undeveloped acreage is not significant.

	Gross	Net
Hugoton Area	216,790	199,590
Anadarko Basin	152,042	113,946
Green River Basin	39,155	26,899

Total	407,987	340,435

The following is a summary of the producing wells on the underlying properties as of December 31, 2001:

	Operated Wells		Nonoperated Wells		Total
	Gross	Net	Gross	Net	Gross	Net
Gas	1,076	978.8	264	62.4	1,340	1,041.2
Oil	129	116.4	6	1.2	135	117.6

Total	1,205	1,095.2	270	63.6	1,475	1,158.8

The following is a summary of the number of wells drilled on the underlying properties during the years indicated. Unless otherwise indicated, all wells drilled are developmental. There were no wells in process of drilling at December 31, 2001.

	2001		2000		1999
	Gross	Net	Gross	Net	Gross	Net
Completed gas wells (a)	46	34.1	40	31.0	40	32.5
Completed oil wells (b)	—	—	1	0.1	—	—
Nonproductive—exploratory	—	—	—	—	1	1.0

Total	46	34.1	41	31.1	41	33.5

(a): Included in completed gas wells are 6 gross (1.3 net) wells drilled on nonoperated interests in 2001, ten gross (1.7 net) wells in 2000 and 7 gross (1.1 net) wells in 1999.
(b): Completed oil wells were drilled on nonoperated interests.

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 production. Because of this two-month interval, the trust's initial accounting year ended December 31, 1999 includes net profits income related to eleven months of oil and gas sales, or December 1998 (the trust's initial month) through

October 1999 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, 2001 were as follows:

			2001	2000	1999
Production
Underlying Properties
	Gas—Sales (Mcf)		36,597,937	36,842,156	34,188,398
		Average per day (Mcf)	100,268	100,662	102,055
	Oil—Sales (Bbls)		393,731	399,929	388,038
		Average per day (Bbls)	1,079	1,093	1,158
Net Profits Interests
	Gas—Sales (Mcf)		17,671,423	18,199,754	15,583,364
		Average per day (Mcf)	48,415	49,726	46,518
	Oil—Sales (Bbls)		190,722	198,677	190,668
		Average per day (Bbls)	523	543	569
Average Sales Price
	Gas (per Mcf)		$ 4.30	$ 3.14	$ 2.12
	Oil (per Bbl)		$27.60	$28.67	$16.53

Oil and Natural Gas Reserves

General

Miller and Lents, Ltd., independent petroleum engineers, has estimated oil and gas reserves attributable to the underlying properties and net profits interests as of December 31, 2001, 2000, 1999 and 1998. 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 80% net profits interests in the properties have effectively been reduced to reflect recovery of the trust's 80% portion of applicable production and development costs, excluding overhead. 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. These 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 revenues are not subject to taxation at the trust level.

Year-end weighted average realized gas prices used to determine the standardized measure were $2.34 per Mcf in 2001, $9.44 per Mcf in 2000, $2.23 per Mcf in 1999 and $2.01 per Mcf in 1998. Year-end oil prices used to determine the standardized measure were based on a West Texas Intermediate crude oil posted price of $16.75 per Bbl in 2001, $23.75 per Bbl in 2000, $22.75 per Bbl in 1999 and $9.50 per Bbl in 1998.

Proved Reserves

(in thousands)		Underlying Properties				Net Profits Interests
		Gas (Mcf)		Oil (Bbls)		Gas (Mcf)		Oil (Bbls)
Balance, December 31, 1998		515,073		4,030		282,297		2,193
	Extensions, discoveries and other additions	28,262		89		16,173		51
	Revisions of prior estimates	(3,778	)	540		5,034		358
	Production—sales volumes	(34,188	)	(388	)	(15,583	)	(191	)

Balance, December 31, 1999		505,369		4,271		287,921		2,411
	Extensions, discoveries and other additions	29,076		132		20,605		94
	Revisions of prior estimates	17,640		544		81,922		957
	Property sales	(225	)	(10	)	(98	)	(4	)
	Production—sales volumes	(36,842	)	(400	)	(18,200	)	(199	)

Balance, December 31, 2000		515,018		4,537		372,150		3,259
	Extensions, discoveries and other additions	18,365		65		8,270		29
	Revisions of prior estimates	(26,582	)	(390	)	(105,407	)	(1,001	)
	Production—sales volumes	(36,598	)	(394	)	(17,671	)	(191	)

Balance, December 31, 2001		470,203		3,818		257,342		2,096

Extensions, discoveries and additions in 1999, 2000 and 2001 are primarily related to delineation of additional proved undeveloped reserves in the Anadarko Basin. Downward revisions of prior estimates of the proved reserves for the underlying properties during 2001 are because of lower prices. Upward revisions of prior estimates of the proved reserves for the underlying properties during 2000 were because of lower than estimated production decline. Upward revisions of prior estimates of proved gas reserves of the net profits interests as compared with downward revisions of the underlying properties in 1999, and higher upward and downward revisions for the net profits interests as compared with the underlying properties in 2000 and 2001, were caused by year-end gas price fluctuations which resulted in increased gas reserves allocated to or from the trust.

Proved Developed Reserves

(in thousands)	Underlying Properties		Net Profits Interests
	Gas (Mcf)	Oil (Bbls)	Gas (Mcf)	Oil (Bbls)
December 31, 1998	435,328	3,368	249,215	1,934

December 31, 1999	431,399	3,595	253,567	2,105

December 31, 2000	434,904	3,935	316,278	2,843

December 31, 2001	401,846	3,297	228,472	1,876

Standardized Measure of Discounted Future Net Cash Flows from Proved Reserves

(in thousands)		December 31
		2001		2000		1999
Underlying Properties
Future cash inflows		$	1,177,447	$	4,972,727	$	1,240,476
Future costs:
	Production		389,721		831,037		388,923
	Development		55,072		60,211		48,861

Future net cash flows			732,654		4,081,479		802,692
10% discount factor			365,760		2,141,117		393,924

Standardized measure		$	366,894	$	1,940,362	$	408,768

Net Profits Interests
Future cash inflows		$	644,489	$	3,593,473	$	707,067
Future production taxes			58,366		328,290		64,913

Future net cash flows			586,123		3,265,183		642,154
10% discount factor			292,608		1,712,894		315,140

Standardized measure		$	293,515	$	1,552,289	$	327,014

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

(in thousands)
			2001			2000			1999
Underlying Properties
Standardized measure, January 1			$	1,940,362		$	408,768		$	347,177

Revisions:
	Prices and costs			(1,626,755	)		1,496,302			70,848
	Quantity estimates			(2,367	)		(5,187	)		(5,493	)
	Accretion of discount			166,273			35,746			31,824
	Future development costs			(20,415	)		(30,339	)		(9,268	)
	Production rates and other			362			283			(1,561	)

		Net revisions		(1,482,902	)		1,496,805			86,350
Extensions, additions and discoveries				8,524			105,929			16,666
Production				(129,457	)		(93,786	)		(53,021	)
Development costs				30,367			22,771			11,596
Sales in place				—			(125	)		—

		Net change		(1,573,468	)		1,531,594			61,591

Standardized measure, December 31			$	366,894		$	1,940,362		$	408,768

Net Profits Interests
Standardized measure, January 1			$	1,552,289		$	327,014		$	277,742
Extensions, discoveries and other additions				6,819			84,743			13,333
Accretion of discount				133,018			28,597			25,459
Revisions of prior estimates, changes in price and other (a)				(1,319,339	)		1,168,847			43,620
Property sales				—			(100	)		—
Net profits income				(79,272	)		(56,812	)		(33,140	)

Standardized measure, December 31			$	293,515		$	1,552,289		$	327,014

(a): Significant revisions in 2001 and 2000 were caused by the changes in year-end gas prices.

Regulation

Natural Gas Regulation

The interstate transportation and sale for resale of natural gas is subject to federal regulation, including transportation rates charged, storage tariffs and various other matters, by the Federal Energy Regulatory Commission. Federal price controls on wellhead sales of domestic natural gas terminated on January 1, 1993. 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, and what effect, if any, such proposals might have on the operations of the underlying properties.

Environmental Regulation

Companies that are engaged in the oil and gas industry are affected by federal, state and local laws regulating the discharge of materials into the environment. Those laws may impact operations of the underlying properties. No material expenses have been incurred on the underlying properties in complying with environmental laws and regulations. XTO Energy does not expect that future compliance will have a material adverse effect on the trust.

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.

Other Regulation

The Minerals Management Service of the United States Department of the Interior is evaluating existing methods of settling royalties on federal and Native American oil and gas leases. Seven percent of the net acres of the underlying properties, primarily located in Wyoming, involve federal leases. Although the final rules could cause an increase in the federal royalties to be paid on these properties, and, correspondingly, decrease the revenue to XTO Energy and the trust, XTO Energy's management does not believe that the proposed rule changes will have a significant detrimental effect on trust distributions.

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.

Tight Sands Tax Credit

The trust receives net profits income from tight sands wells, certain production from which qualifies for the federal income tax credit for producing nonconventional fuels under Section 29 of the Internal Revenue Code. The Section 29 tax credit is available for tight sands gas produced and sold through 2002 from wells drilled prior to January 1, 1993 and after November 5, 1990, or after December 31, 1979 if the related formation was dedicated to interstate commerce as of April 20, 1977. This tax credit is approximately $0.52 per MMBtu. Such 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 is considering an extension of existing energy tax credits beyond the scheduled December 31, 2002 expiration date, as well as the creation of similar new tax credits. During 2001, the U.S. House passed a bill that would extend existing Section 29 tax credits on certain production, while the U.S. Senate is considering a separate bill to address energy tax credits, including Section 29. The potential effect of any final legislation on unitholders is unknown.

Pricing and Sales Information

A subsidiary of XTO Energy purchases most of XTO Energy's natural gas production at the monthly published index price, then sells the gas to third parties for the best available price. Any marketing gains or losses are not included in trust net proceeds. Oil production is generally marketed at the wellhead to third parties at the best available price. XTO Energy arranges for some of its natural gas to be processed by unaffiliated third parties and markets the natural gas liquids. The natural gas attributable to the underlying properties is marketed under contracts existing at trust inception. Contracts covering production from the Ringwood area of Major County are generally for the life of the lease, and the contract for the majority of production from the Hugoton area expires in 2004. If new contracts are entered with unaffiliated third parties, the proceeds from sales under those new contracts will be included in gross proceeds from the underlying properties. If new contracts are entered with XTO Energy's marketing subsidiary, it may charge XTO Energy a fee that may not exceed 2% of the sales price of the oil and natural gas received from unaffiliated parties. The sales price is net of any deductions for transportation from the wellhead to the unaffiliated parties and any gravity or quality adjustments.

Item 3. Legal Proceedings

On April 3, 1998, a class action lawsuit, Booth, et al. v. Cross Timbers Oil Company, was filed in the District Court of Dewey County, Oklahoma by royalty owners of natural gas wells in Oklahoma. The plaintiffs allege that since 1991, XTO Energy has underpaid royalty owners as a result of reducing royalties for improper charges for production, marketing, gathering, processing and transportation costs and selling natural gas through affiliated companies at prices less favorable than those paid by third parties. No class has been certified. The court has ordered that the parties enter into mediation, which should occur in the first half of 2002. XTO Energy believes that it has strong defenses to this lawsuit and intends to vigorously defend its position. However, if XTO Energy ultimately makes any payments, the trust will bear its 80% share of such payments related to production from the underlying properties for periods since December 1, 1998. Additionally, if a judgment or settlement increases the amount of future payments to royalty owners, the trust would bear its proportionate share of the increased payments through reduced net proceeds. The amount of any potential settlement related to the trust and reduction in net proceeds is not presently determinable, but, in XTO Energy management's opinion, is not currently expected to be material to the trust's annual distributable income, financial position or liquidity.

A second lawsuit, United States of America ex rel. Grynberg v. Cross Timbers Oil Company, et al., was filed in the United States District Court for the Western District of Oklahoma. This action alleges that XTO Energy underpaid royalties on natural gas produced from federal leases and lands owned by Native Americans by at least 20% during the past ten years as a result of mismeasuring the volume of natural gas and wrongfully analyzing its heating content. The suit, which was brought under the qui tam provisions of the U.S. False Claims Act, seeks treble damages for the unpaid royalties (with interest), civil penalties between $5,000 and $10,000 for each violation of the U.S. False Claims Act, and an order for XTO Energy to cease the allegedly improper measuring practices. The cases against XTO Energy and other defendants have been consolidated in the United States District Court for Wyoming. While XTO Energy is unable to predict the outcome of this case or estimate the amount of any possible loss, it believes that the allegations of this lawsuit are without merit and intends to vigorously defend the action. However, an order to change measuring practices or a related settlement could adversely affect the trust by reducing net proceeds in the future by an amount that is presently not determinable, but, in XTO Energy management's opinion, is not currently expected to be material to the trust's annual distributable income, financial position or liquidity.

In June 2001, XTO Energy was served with a third lawsuit styled Quinque Operating Co., et al. v. Gas Pipelines, et al. The action was filed in the District Court of Stevens County, Kansas, against XTO Energy and one of its subsidiaries, along with over 200 natural gas transmission companies, producers, gatherers and processors of natural gas. Plaintiffs sought to represent a class of plaintiffs consisting of all similarly situated royalty owners, overriding royalty owners and working interest owners either from whom defendants had purchased natural gas or who received economic benefit from the sale of such gas since January 1, 1974. The complaint alleged that the defendants had mismeasured both the volume and heating content of natural gas delivered into their pipelines resulting in underpayments to plaintiffs. The plaintiffs dismissed XTO Energy and its subsidiary as a defendant and substituted another subsidiary as a defendant. Any potential liability of the subsidiary will not affect the trust's net proceeds.

Certain of the trust properties are involved in various other 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 2001.

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, 2001 is incorporated herein by reference.

Item 6. Selected Financial Data

	Year Ended December 31
	2001		2000		1999
Net Profits Income	$	79,272,395	$	56,812,141	$	33,139,662
Distributable Income		79,131,040		56,712,080		33,090,049
Distributable Income per Unit		1.978276		1.417802		0.827253
Distributions per Unit		1.978276		1.417802		0.827253
Total Assets at Year-End		217,127,992		232,057,603		237,980,449

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, 2001 on pages 5 and 6 of the trust's Annual Report to unitholders for the year ended December 31, 2001 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 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, 2001, other than the December distribution payable to unitholders in January 2002, 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.

Related Party Transactions

The underlying properties from which the net profits interests were carved are currently owned by XTO Energy, which operates approximately 90% of the wells on the underlying properties. In computing net proceeds, XTO Energy deducts a monthly overhead charge for reimbursement of administrative expenses on the underlying properties it operates. As of December 31, 2001, the monthly overhead charge was approximately $678,000 ($542,000 net to the trust) and is subject to annual adjustment based on a oil and gas industry index. As of March 1, 2002, XTO Energy owned 21,705,893, or 54.3%, of the 40,000,000 outstanding units.

XTO Energy sells a significant portion of natural gas production from the underlying properties to certain of XTO Energy's wholly owned subsidiaries under contracts in existence when the trust was created, generally at amounts approximating monthly published market prices. For further information regarding natural gas sales from the underlying properties to affiliates of XTO Energy, see Item 2, Properties, and Note 6 to Financial Statements in the accompanying annual report. Total gas sales from the underlying properties to XTO Energy's wholly owned subsidiaries were $128.5 million for the year ended December 31, 2001, or 82% of total gas sales, $89.0 million for the year ended December 31, 2000, or 77% of total gas sales, and $55.9 million for the year ended December 31, 1999, or 77% of total gas sales.

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 accompanying annual report.

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. 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, is prepared using assumptions required by the Financial Accounting Standards Board and the Securities and Exchange Commission. Such assumptions include using year-end oil and gas prices and year-end costs for estimated future development and production expenditures. Discounted future net cash flows are calculated using a 10% rate. Changes in any of these assumptions, including consideration of other factors, could have a significant impact on the standardized measure. Accordingly, the standardized

measure does not represent XTO Energy's or the trustee's estimated current market value of proved reserves.

Forward-Looking Statements

Certain information included in this annual report and other materials filed, or to be filed, by the trust with the Securities and Exchange Commission (as well as information included in oral statements or other written statements made or to be made by XTO Energy or the trustee) contain forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended, and Section 27A of the Securities Act of 1933, as amended, relating to the trust operations of the underlying properties and the oil and gas industry. Such forward-looking statements may concern, among other things, development activities, 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. Any number of factors could cause actual results to differ materially, including, but not limited to, crude oil and natural gas price fluctuations, changes in the underlying demand for oil and natural gas, changes in ownership and/or the operator of the underlying properties, the timing and results of development activity, the availability of drilling equipment, as well as general domestic and international economic and political conditions.

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 the trust's 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 report of Arthur Andersen LLP dated March 19, 2002, appearing on pages 8 through 12 of the trust's Annual Report to unitholders for the year ended December 31, 2001 are incorporated herein by reference.

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

There have been no changes in accountants or disagreements with accountants on any matter of accounting principles or practices or financial statement disclosures during the two years ended December 31, 2001.

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.

Item 11. Executive Compensation

The trustee received the following annual compensation from 1999 through 2001 as specified in the trust indenture:

Name and Principal Position	Year	Other Annual Compensation (1)
Bank of America, N.A., Trustee	2001	$	35,000
	2000		35,000
	1999		29,333

(1): Under the trust indenture, the trustee is entitled to an annual administrative fee, paid in equal monthly installments. Such fee can be adjusted annually based on an oil and gas industry index. Upon termination of the trust, the trustee is entitled to a termination fee of $15,000.

Item 12. Security Ownership of Certain Beneficial Owners and Management

(a) Security Ownership of Certain Beneficial Owners. The following table sets forth as of March 1, 2002 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.		21,705,893 units (1)		54.3%
810 Houston Street, Suite 2000 Fort Worth, Texas 76102

(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 January 31, 2002, Bank of America, N.A. owned, in various fiduciary capacities, an aggregate of 7,400 units without the right to vote any 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.

Item 13. Certain Relationships and Related Transactions

In computing net profits income paid to the trust for the net profits interests, XTO Energy deducts an overhead charge for reimbursement of administrative expenses on the underlying properties it operates. This charge at December 31, 2001 was approximately $678,000 per month, or $8,136,000 annually (net to the trust of $542,400 per month or $6,508,800 annually), and is subject to annual adjustment based on an oil and gas industry index.

XTO Energy sells a significant portion of natural gas production from the underlying properties to certain of its wholly owned subsidiaries under contracts in existence when the trust was created, generally at amounts approximating monthly published prices. For further information, see Item 2 "Hugoton Area," "Anadarko Basin," "Green River Basin" and "Pricing and Sales Information."

PART IV

Item 14. 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)

Report of Independent Public Accountants

Statements of Assets, Liabilities and Trust Corpus at December 31, 2001 and 2000

Statements of Distributable Income for the years ended December 31, 2001, 2000 and 1999

Statements of Changes in Trust Corpus for the years ended December 31, 2001, 2000 and 1999

Notes to Financial Statements

2.: Financial Statement Schedules

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

3.: Exhibits


(4)	(a)	Hugoton Royalty Trust Indenture by and between NationsBank, N.A. (now Bank of America, N.A.), as trustee, and XTO Energy Inc. heretofore filed as Exhibit 4.1 to the trust's Registration Statement No. 333-68441 on Form S-1 filed with the Securities and Exchange Commission on December 4, 1998, is incorporated herein by reference.
	(b)	Net Overriding Royalty Conveyance (Hugoton Royalty Trust, 80%—Kansas) as amended and restated from XTO Energy Inc. to NationsBank, N.A. (now Bank of America, N.A.), as trustee, and XTO Energy Inc. dated December 1, 1998, heretofore filed as Exhibit 10.1.1 to the trust's Registration Statement No. 333-68441 on Form S-1 filed with the Securities and Exchange Commission on March 16, 1999, is incorporated herein by reference.
	(c)	Net Overriding Royalty Conveyance (Hugoton Royalty Trust, 80%—Oklahoma) as amended and restated from XTO Energy Inc. to NationsBank, N.A. (now Bank of America, N.A.), as trustee, and XTO Energy Inc. dated December 1, 1998, heretofore filed as Exhibit 10.1.2 to the trust's Registration Statement No. 333-68441 on Form S-1 filed with the Securities and Exchange Commission on March 16, 1999, is incorporated herein by reference.
	(d)	Net Overriding Royalty Conveyance (Hugoton Royalty Trust, 80%—Wyoming) as amended and restated from XTO Energy Inc. to NationsBank, N.A. (now Bank of America, N.A.), as trustee, and XTO Energy Inc. dated December 1, 1998, heretofore filed as Exhibit 10.1.3 to the trust's Registration Statement No. 333-68441 on Form S-1 filed with the Securities and Exchange Commission on March 16, 1999, is incorporated herein by reference.
(13)		Hugoton Royalty Trust Annual Report to unitholders for the year ended December 31, 2001
(23.1)		Consent of Arthur Andersen LLP
(23.2)		Consent of Miller and Lents, Ltd.
(99.1)		Assurance Letter Regarding Arthur Andersen LLP

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, 2001, there were no reports filed on Form 8-K by the trust with the Securities and Exchange Commission.

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.

	HUGOTON ROYALTY TRUST By BANK OF AMERICA, N.A., TRUSTEE
	By:	RON E. HOOPER Ron E. Hooper Senior Vice President
	XTO ENERGY INC.
Date: March 27, 2002	By:	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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PART I
PART II
PART III
PART IV
SIGNATURES
EX-13 3 a2073906zex-13.txt EXHIBIT 13 EXHIBIT 13 HUGOTON 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 net profits percentage of 80%, which is paid to the trust by XTO Energy. "Net profits income" is referred to as "royalty income" for tax reporting 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: 80% net profits interests - interests that entitle the trust to receive 80% of the net proceeds from the underlying properties that are working interests in Kansas, Oklahoma and Wyoming. underlying properties XTO Energy's interest in certain oil and gas properties from which the net profits interests were conveyed. The underlying properties include working interests in predominantly gas-producing properties located in Kansas, Oklahoma and Wyoming. 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 and development costs THE TRUST Hugoton Royalty Trust was created on December 1, 1998 when XTO Energy Inc. (formerly known as Cross Timbers Oil Company) conveyed 80% net profits interests in certain predominantly gas-producing properties located in Kansas, Oklahoma and Wyoming to the trust. 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 began trading on the New York Stock Exchange on April 9, 1999 under the symbol "HGT." The following are the high and low unit sales prices and total cash distributions per unit paid by the trust during each quarter of 2001 and 2000:

At December 31, 2001, there were 40,000,000 units outstanding and approximately 156 unitholders of record; 17,757,839 of these units were held by depository institutions. As of March 1, 2002, XTO Energy owned 21,705,893 units. 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 II, Item 7 of the accompanying Form 10-K. Although XTO Energy believes 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. 1 SUMMARY The trust was created to collect and distribute to unitholders monthly net profits income related to the 80% net profits interests. Such net profits income is calculated as 80% of the net proceeds received from certain working interests in predominantly gas-producing properties in Kansas, Oklahoma and Wyoming. Net proceeds from properties in each state are calculated by deducting production costs, development costs and overhead from revenues. If monthly costs exceed revenues from the underlying properties in any state, such excess costs must be recovered, with accrued interest, from future net proceeds of that state and cannot reduce net profits income from another state. Excess costs generally can occur during periods of higher development activity and lower gas prices. Unitholders may be eligible to receive the following tax benefits, but should consult their tax advisors: - THE NONCONVENTIONAL FUEL SOURCE TAX CREDIT is related to tight sands gas production sold through 2002 from wells drilled on the underlying properties prior to January 1, 1993, and after November 5, 1990, or after December 31, 1979 if the related formation was dedicated to interstate commerce as of April 20, 1977. This tax credit may be used to reduce the unitholder's regular income tax liability, but not below his tentative minimum tax. Congress is considering an extension of existing energy tax credits beyond the scheduled December 31, 2002 expiration date, as well as the creation of similar new tax credits. During 2001, the U.S. House passed a bill that would extend existing tax credits on certain production, while the U.S. Senate is considering a separate bill to address energy tax credits. The potential effect of any final legislation on unitholders is unknown. - COST DEPLETION is generally available to unitholders as a deduction from royalty 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 2001 and held them throughout 2001 would be entitled to a cost depletion deduction of approximately 5% of his cost. Assuming a cost of $13.50 per unit, cost depletion would offset 33% of 2001 taxable trust income. After considering the tight sands tax credit and assuming a 30% tax rate, the 2001 taxable equivalent return as a percentage of unit cost would be 17%. (NOTE- because the units are a depleting asset, a portion of this return is effectively a return of capital.) 2 TO UNITHOLDERS We are pleased to present the 2001 Annual Report of the Hugoton Royalty Trust. This report includes a copy of the trust's 2001 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, 2001, net profits income totaled $79,272,395. After adding interest income of $136,177 and deducting trust administration expense of $277,532, distributable income was $79,131,040 or $1.978276 per unit. Net profits income and distributions were 40% higher than 2000 amounts primarily because of higher average gas prices. Natural gas prices averaged $4.30 per Mcf for 2001, 37% higher than the 2000 average price of $3.14 per Mcf. The average 2001 oil price was $27.60 per Bbl, 4% lower than the 2000 average price of $28.67 per Bbl. Gas sales volumes from the underlying properties for 2001 were 36,597,937 Mcf, or 100,268 Mcf per day, versus 100,662 Mcf per day in 2000. Oil sales volumes from the underlying properties were 393,731 Bbls, or 1,079 Bbls per day in 2001, as compared with 1,093 Bbls per day in 2000. For further information on sales volumes and product prices, see "Trustee's Discussion and Analysis." Tight sands gas sales volumes from the underlying properties were 2,104,845 Mcf in 2001. After reduction of volumes related to production and development costs, tight sands gas sales volumes allocated to the net profits interests were 1,230,270 Mcf, resulting in a tight sands tax credit for the year of $0.017309 per unit. This credit (or a portion thereof, if units were acquired after January 2001) is available to be applied against the unitholder's regular federal income tax liability, subject to certain limitations. Unitholders should consult their tax advisors regarding use of this credit. As of December 31, 2001, proved reserves for the net profits interests were estimated by independent engineers to be 257.3 Bcf of natural gas and 2.1 million Bbls of oil. Estimated gas reserves decreased 31% and oil reserves decreased 36% from year-end 2000 to 2001, primarily because of the decrease in year-end realized gas prices from $9.44 to $2.34 per Mcf and West Texas Intermediate posted oil prices from $23.75 to $16.75 per Bbl, as well as the resulting decreased allocation of reserves to the net profits interests. All reserve information prepared by independent engineers has been provided to the trustee by XTO Energy. Estimated future net revenues from proved reserves of the net profits interests at December 31, 2001 are $586.1 million, or $14.65 per unit. Using an annual discount factor of 10%, the present value of estimated future net revenues at December 31, 2001 is $293.5 million, or $7.34 per unit. Proved reserve estimates and related future net revenues have been determined based on year-end oil and gas prices, as well as other guidelines prescribed by the Financial Accounting Standards Board as further described under Item 2 of the accompanying Form 10-K. The present value of estimated future net revenues is not necessarily representative of the market value of trust units. As discussed in the tax instructions provided to unitholders in February 2002, trust distributions are considered portfolio income, rather than passive income. Unitholders should consult their tax advisors for further information. Hugoton Royalty Trust By: Bank of America, N.A., Trustee By: Ron E. Hooper Senior Vice President 3 THE UNDERLYING PROPERTIES The underlying properties are predominantly gas-producing properties with established production histories in the Hugoton area of Oklahoma and Kansas, the Anadarko Basin of Oklahoma and the Green River Basin of Wyoming. The average reserve-to-production index for the underlying properties as of December 31, 2001 is approximately 14 years. This index is calculated using total proved reserves and estimated 2002 production for the underlying properties. Based on estimated future net revenues at year-end oil and gas prices, the proved reserves of the underlying properties are approximately 94% natural gas and 6% oil. XTO Energy operates approximately 90% of the underlying properties. Because the underlying properties are working interests, production and development costs are deducted in calculating net profits income. As a result, net profits income is affected by the level of maintenance and development activity on the underlying properties. See "Trustee's Discussion and Analysis - Years Ended December 31, 2001, 2000 and 1999 - Costs." Total 2001 development costs for the underlying properties were $30,367,276, an increase of 33% from the prior year. XTO Energy has notified the trustee that total budgeted development costs for 2002 for the underlying properties are $23.1 million. HUGOTON AREA Discovered in 1922, the Hugoton area is the largest natural gas producing area in North America. During 2001, gas sales volumes from the Hugoton area were 11,257,000 Mcf, or approximately 31% of total sales volumes from the underlying properties. Most of the production is from the Chase formation at depths of 2,700 to 2,900 feet. XTO Energy plans to develop other formations, including the Council Grove, Chester, Morrow and St. Louis formations that underlie the 79,500 net acres held by production by the Chase formation wells. XTO Energy has participated in 3-D seismic shoots covering 30,000 acres of its net acreage position beneath the Chase formation. Although increased density drilling was ultimately not approved by the Oklahoma legislature, Oklahoma regulations were amended in July 1998 to increase allowable production in the Oklahoma panhandle from 150,000 Mcf per day to 450,000 Mcf per day, which lifted curtailment in this area. During 2001, development of the Hugoton Area included successful recompletions to the Towanda Formation. XTO Energy also embarked on a pilot project to test new restimulation techniques in the Chase intervals. XTO Energy completed 27 of these restimulations in 2001. During 2002, XTO Energy plans to perform seven Towanda completions and 46 Chase restimulations. ANADARKO BASIN The Anadarko Basin of western Oklahoma was discovered in 1945. Gas sales volumes from the Anadarko Basin totaled 16,239,000 Mcf in 2001, or approximately 44% of total sales volumes from the underlying properties. XTO Energy is one of the largest producers in the Ringwood, Northwest Okeene and Cheyenne Valley fields in Major County, the principal producing region of the underlying properties in the Anadarko Basin. In Major and Woodward counties, the Mississippian (Osage), Chester and Red Fork formations were the primary drilling targets in 2001. In Major County, XTO Energy successfully drilled and (CONTINUED ON NEXT PAGE)

(a) Based on year-end oil and gas prices. For further information regarding trust proved reserves, 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 (and the tax benefit of the estimated tight sands tax credit) since future net revenues are not subject to taxation at the trust level. 4 completed 13 gross (10.5 net) wells. XTO Energy plans to drill up to six wells and perform up to 19 workovers in Major County in 2002. In Woodward County, the Chester Formation with its four separate producing intervals, was the primary target for 16 gross (13.5 net) wells successfully drilled and completed during 2001. During 2002, XTO Energy plans to drill up to 12 gross (8.3 net) wells and perform up to six workovers in Woodward County. GREEN RIVER BASIN The Green River Basin is located in southwestern Wyoming. Natural gas was discovered in the Fontenelle field of the Green River Basin in the early 1970s. The producing reservoirs are the Cretacious-aged Frontier and Dakota sandstones at depths ranging from 7,500 to 10,000 feet. Gas sales volumes from the Green River Basin were 9,101,000 Mcf in 2001, or approximately 25% of total sales volumes from the underlying properties. XTO Energy drilled and completed six gross (6.0 net) wells in the Fontenelle Unit in 2001. Drilling focused on continued 80-acre and 40-acre infill development of the Frontier sandstones. XTO Energy plans to perform up to six workovers in the Green River Basin during 2002. XTO Energy may also drill up to three development wells, depending on gas prices in 2002. TRUSTEE'S DISCUSSION AND ANALYSIS YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999 Net profits income for 2001 was $79,272,395, as compared with $56,812,141 for 2000 and $33,139,662 for 1999. The 40% increase in net profits income from 2000 to 2001 was primarily because of higher gas prices, while the 71% increase in net profits income from 1999 to 2000 was primarily because of higher gas and oil prices. During 2001, approximately 94%, and in 2000 and 1999, approximately 90%, of net profits income was derived from natural gas sales. Trust administration expense was $277,532 in 2001 as compared to $228,211 in 2000 and $95,987 in 1999. Administration expense was lower in 1999, the trust's initial accounting year, because of costs not billed and paid until 2000. Increased administration expense from 2000 to 2001 is primarily related to increased unitholder reporting costs. Interest income was $136,177 in 2001, $128,150 in 2000 and $46,374 in 1999. Increases in interest income are attributable to higher net profits income. Distributable income was $79,131,040 or $1.978276 per unit in 2001, $56,712,080 or $1.417802 per unit in 2000 and $33,090,049 or $0.827253 per unit in 1999. 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 and gas production. Because of this two-month interval, the trust's initial accounting year ended December 31, 1999 includes net profits income related to only eleven months of oil and gas sales, or December 1998 through October 1999 production. Net profits income is generally affected by three major factors: o oil and gas sales volumes, o oil and gas sales prices, and o costs deducted in the calculation of net profits income. VOLUMES From 2000 to 2001, underlying gas sales volumes decreased 1% and underlying oil sales volumes decreased 2% primarily because natural production decline slightly exceeded the effects of new wells and workovers. From 1999 to 2000, underlying gas sales volumes increased 8% and underlying oil sales volumes increased 3% primarily because of the lag effect of cash receipts in the trust's initial accounting period, which resulted in less than eleven full months of sales volumes in 1999. PRICES GAS. The 2001 average gas price was $4.30 per Mcf, a 37% increase from the 2000 average gas price of $3.14, which was a 48% increase from the 1999 average gas price of $2.12 per Mcf. The 1999 average gas price included the effect of adding $4,977,110 ($3,981,688 net to the trust) to net profits income to achieve a $2.00 minimum price contractually provided to unitholders for distributions through March 2000. As of April 2000, there were no longer any minimum price provisions. See Note 3 to the financial statements. The actual 1999 average price of $1.96 reflects lower prices caused by high levels of gas remaining in storage from the abnormally warm winter of 1998-1999. Gas prices began to increase in May 1999 and, after declining briefly at year end, strengthened in 2000 reaching a record high of $10.10 per MMBtu in December 2000 as winter demand strained gas supplies. Gas prices declined during 2001 because of fuel switching due to higher prices, milder weather and a weaker economy which has reduced the demand for gas and resulted in sharply increased gas storage levels. The average NYMEX price for January and February 2002 was $2.23 per MMBtu. Gas prices have risen in March to an average NYMEX price of $2.93 through March 25. The trust's recent average gas price has been approximately $0.30 per MMBtu lower than the NYMEX price. OIL. The average oil price for 2001 was $27.60 per Bbl, 4% lower than the 2000 average oil price of $28.67 per Bbl, which was 73% higher than the 1999 average price of $16.53 per Bbl. After OPEC members and other oil producers agreed to production cuts in March 1999, oil prices climbed through the remainder of 1999 and first quarter 2000. Despite OPEC production increases in 2000, increased demand sustained higher prices. The West Texas Intermediate ("WTI") posted price reached $34.25 per Bbl in 5 September 2000, its highest level in ten years. Lagging demand in 2001, resulting from a worldwide economic slowdown, caused oil prices to decline. OPEC members agreed to cut daily production by one million barrels in April and an additional one million barrels in September to adjust for weak demand and excess supply. The economic decline was accelerated by the terrorist attacks in the United States on September 11, 2001, placing additional downward pressure on oil prices. In December, OPEC announced further production cuts of 1.5 million barrels per day effective January 1, 2002, for six months. The average WTI posted price for January and February 2002 was $17.06. Oil prices have risen in March to an average WTI posted price of about $21.00 through March 25. Recent trust oil prices have averaged approximately $2.15 higher than the WTI posted price. COSTS The calculation of net profits income includes deductions for production and development costs and overhead since the related underlying properties are working interests. If monthly costs exceed revenues for any state, such excess costs must be recovered, with accrued interest, from future net proceeds of that state and cannot reduce net profits income from another state. Costs exceeded revenues from properties underlying the Wyoming net profits interests in August 1999 because of new wells drilled. All excess costs and accrued interest were fully recovered in September 1999. Taxes, transportation and other generally fluctuates with changes in total revenues. Overhead fluctuates based on changes in the active well count and drilling activity on the underlying properties, as well as an annual inflation adjustment. PRODUCTION. Production expenses increased 11% from 2000 to 2001 because of the timing of maintenance projects and higher compressor rentals. Production expenses increased 30% from 1999 to 2000 because of prior period compressor fuel charges in 2000 and the timing of maintenance projects. DEVELOPMENT. Development costs were $30,367,276 in 2001, $22,771,150 in 2000 and $11,596,495 in 1999. The increases are attributable to new wells drilled and workovers in Oklahoma. Development costs for the calendar year 2001 budget were higher than the initial estimate of $23 million primarily because of higher drilling, service, and equipment costs related to demand generated by higher natural gas prices and carryover of costs from the 2000 budget. In 2001, development costs deducted from distributions totaled $30.4 million, compared with actual development costs of $35.2 million. This $4.8 million excess was almost fully recovered in January and February as the 2002 monthly budgeted development cost deduction of $1.9 million exceeded actual costs. As of the March 2002 distribution, cumulative actual development costs exceeded the amount deducted by $231,000. OTHER PROCEEDS Net profits income for 2001 includes proceeds of $307,824 from the sale of underlying properties in Sweetwater County, Wyoming. FOURTH QUARTER 2001 AND 2000 During fourth quarter 2001 the trust received net profits income totaling $8,507,804, compared with fourth quarter 2000 net profits income of $18,291,467. The 53% decrease in net profits income from fourth quarter 2000 to 2001 was primarily because of lower product prices partially offset by lower costs. Administration expense was $42,941 and interest income was $8,217, resulting in fourth quarter 2001 distributable income of $8,473,080, or $0.211827 per unit. Distributable income for fourth quarter 2000 was $18,311,880 or $0.457797 per unit. Distributions to unitholders for the quarter ended December 31, 2001 were:

VOLUMES Fourth quarter underlying gas sales volumes increased 1% while underlying oil sales volumes declined 3%. Oil and gas sales volumes fluctuations are primarily because of the offsetting effects of new wells and natural production decline. PRICES The average fourth quarter 2001 gas price was $2.19 per Mcf, or 47% lower than the fourth quarter 2000 average price of $4.12. The average fourth quarter oil price was $25.02 per Bbl, or 23% lower than the fourth quarter 2000 average price of $32.34. For further information about product prices, see "Years Ended December 31, 2001, 2000 and 1999 - Prices" above. COSTS PRODUCTION. Fourth quarter production expenses decreased 35% from 2000 to 2001 because of prior period salt water disposal adjustments recorded in fourth quarter 2001 and prior period fuel adjustments recorded in fourth quarter 2000. DEVELOPMENT. Development costs decreased 41% from fourth quarter 2000 to 2001 primarily because of reduced drilling activity in fourth quarter 2001. For further information about costs, see "Years Ended December 31, 2001, 2000 and 1999 - Costs" above. See Item 7 of the accompanying Form 10-K for disclosures regarding liquidity and capital resources, contractual obligations and commitments, related party transactions and critical accounting policies of the trust. See Item 7a of the accompanying Form 10-K for quantitative and qualitative disclosures about market risk affecting the trust. 6 CALCULATION OF NET PROFITS INCOME The following is a summary of the calculation of net profits income received by the trust:

(a) Because of the two-month interval between time of production and receipt of net profits income by the trust: 1) oil and gas sales for the year ended December 31, 1999 generally relate to eleven months of production for the period December 1998 (the trust's initial month) through October 1999, 2) oil and gas sales for the year ended December 31, 2001 and 2000 generally relate to twelve months of production for the period November through October, and 3) oil and gas sales for the three months ended December 31 generally relate to production for the period August through October. (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 expenses and development costs. Changes in any of these factors may result in disproportionate fluctuations in volumes allocated to the net profits interests. Therefore, comparative discussion of oil and gas sales volumes is based on the underlying properties. (c) During 2001, the costs related to well recompletions and remedial workovers were classified as development costs, consistent with their budget classification. These costs were previously included in production expense. The costs are reclassified in prior periods for consistency with current presentation. (d) See Note 4 to Financial Statements. 7 HUGOTON ROYALTY TRUST STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS

STATEMENTS OF DISTRIBUTABLE INCOME

STATEMENTS OF CHANGES IN TRUST CORPUS

See Accompanying Notes to Financial Statements. 8 HUGOTON ROYALTY TRUST NOTES TO FINANCIAL STATEMENTS 1. TRUST ORGANIZATION AND PROVISIONS Hugoton Royalty Trust was created on December 1, 1998 by XTO Energy Inc. (formerly known as "Cross Timbers Oil Company"). Effective on that date, XTO Energy conveyed 80% net profits interests in certain predominantly gas-producing working interest properties in Kansas, Oklahoma and Wyoming to the trust under separate conveyances for each of the three states. XTO Energy currently owns and operates the majority of the underlying working interest properties. In exchange for the conveyances of the net profits interests to the trust, 40 million units of beneficial interest in the trust were issued to XTO Energy. On April 8, 1999, XTO Energy sold 15 million units in the trust's initial public offering. On May 7, 1999, XTO Energy sold an additional 2 million units pursuant to the underwriters' overallotment option. In 1999 and 2000, XTO Energy sold 1.3 million units to certain of its officers. The trust did not receive any proceeds from the sale of trust units. Bank of America, N.A. is the trustee for the trust. The trust indenture provides, among other provisions, that: - 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 may dispose of all or part of the net profits interests if approved by 80% of the unitholders, or upon trust termination. Otherwise, the trust may sell up to 1% of the value of the net profits interests in any calendar year, pursuant to notice from XTO Energy of its desire to sell the related underlying properties. 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 to pay trust liabilities if repaid in full 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 proceeds from the underlying properties falling below $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 generally accepted accounting principles: - Net profits income is recorded in the month received by the trustee (Note 3). - 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 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 contingencies that would not be recorded under generally accepted accounting principles. The initial carrying value of the net profits interests of $247,066,951 was XTO Energy's historical net book value of the interests on December 1, 1998, 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 $31,720,759 as of December 31, 2001 and $20,985,508 as of December 31, 2000. 3. DISTRIBUTIONS TO UNITHOLDERS The trustee determines the amount to be distributed to unitholders each month by totaling net profits income, interest income and other cash receipts, and subtracting liabilities paid and adjustments in cash reserves established by the trustee. The resulting amount is distributed to unitholders of record within ten business days after the monthly record date, which is 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 80%. Net proceeds are the gross proceeds received from the sale of production, less costs. Costs generally include applicable taxes, transportation, legal and marketing charges, production costs, development and drilling costs, and overhead (Note 6). For monthly trust distributions declared through March 2000, the related net profits income was based on gross proceeds equal to the greater of: - the actual amount received from sales of production, or - the imputed amount that would be received from sales of production at a gas price of $2.00 per Mcf. For the year ended December 31, 1999, imputed proceeds based on a $2.00 gas price exceeded actual proceeds by $4,977,110 ($3,981,688 net to the trust). For the year ended December 31, 2000, there were no imputed proceeds because actual gas prices were higher than the $2.00 price support. XTO Energy, as owner of the underlying properties, computes net profits income separately for each of the three conveyances (Note 1). If 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 the other conveyances. 9 4. DEVELOPMENT COSTS For the year ended December 31, 2001, XTO Energy deducted development costs of $30.4 million, compared with actual development costs of $35.2 million. This $4.8 million excess was almost fully recovered in January and February as the 2002 monthly budgeted development cost deduction of $1.9 million exceeded actual costs. As of the March 2002 distribution, cumulative actual development costs exceed the amount deducted by $231,000. 5. 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 the trust's 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. XTO Energy has advised the trustee that the trust receives net profits income from tight sands gas wells. Production sold through 2002 from wells drilled on the underlying properties prior to January 1, 1993, and after November 5, 1990 (or after December 31, 1979 if the related formation was dedicated to interstate commerce as of April 20, 1977), qualifies for the federal income tax credit for producing nonconventional fuels under Section 29 of the Internal Revenue Code. This tax credit was approximately $0.52 per MMBtu and $0.017309 per unit in 2001, $0.014499 per unit in 2000 and $0.016093 per unit in 1999. The credit is recalculated annually based on each year's qualifying production through the year 2002. Unitholders should consult their tax advisors regarding use of this credit and other trust tax compliance matters. Congress is considering an extension of existing energy tax credits beyond the scheduled December 31, 2002 expiration date, as well as the creation of similar new tax credits. During 2001, the U.S. House passed a bill that would extend existing Section 29 tax credits on certain production, while the U.S. Senate is considering a separate bill to address energy tax credits, including Section 29. The potential effect of any final legislation on unitholders is unknown. 6. XTO ENERGY INC. XTO Energy operates approximately 90% of the wells on the underlying properties. In computing net proceeds, XTO Energy deducts an overhead charge for reimbursement of administrative expenses on the underlying properties it operates. As of December 31, 2001, the overhead charge was approximately $678,000 ($542,400 net to the trust) per month and is subject to annual adjustment based on an oil and gas industry index. As of March 1, 2002, XTO Energy owned 54.3% of the trust. XTO Energy sells a significant portion of natural gas production from the underlying properties to certain of XTO Energy's wholly owned subsidiaries under contracts in existence when the trust was created, generally at amounts approximating monthly published market prices. Most of the production from the Hugoton area is sold under a contract to Timberland Gathering & Processing Company, Inc. ("TGPC"). Much of the gas production in Major County, Oklahoma is sold to Ringwood Gathering Company ("RGC"), which retains a $0.315 per Mcf compression and gathering fee. TGPC and RGC sell gas to Cross Timbers Energy Services, Inc. ("CTES"), which markets gas to third parties. XTO Energy sells directly to CTES most gas production not sold directly to TGPC or RGC. Total gas sales from the underlying properties to XTO Energy's wholly owned subsidiaries were $128.5 million for the year ended December 31, 2001, or 82% of total gas sales, $89.0 million for the year ended December 31, 2000, or 77% of total gas sales, and $55.9 million for the year ended December 31, 1999, or 77% of total gas sales. 7. LITIGATION XTO Energy is a defendant in two separate lawsuits that could, if adversely determined, decrease future trust distributable income. Any damages relating to production prior to the formation of the trust will be borne by XTO Energy. On April 3, 1998, a class action lawsuit, Booth, et al. v. Cross Timbers Oil Company, was filed in the District Court of Dewey County, Oklahoma by royalty owners of natural gas wells in Oklahoma. The plaintiffs allege that since 1991, XTO Energy has underpaid royalty owners as a result of reducing royalties for improper charges for production, marketing, gathering, processing and transportation costs and selling natural gas through affiliated companies at prices less favorable than those paid by third parties. No class has been certified. The court has ordered that the parties enter mediation, which should occur in the first half of 2002. XTO Energy believes that it has strong defenses to this lawsuit and intends to vigorously defend its position. However, if XTO Energy ultimately makes any payments, the trust will bear its 80% share of such payments related to production from the underlying properties for periods since December 1, 1998. Additionally, if a judgment or settlement increases the amount of future payments to royalty owners, the trust would bear its proportionate share of the increased payments through reduced net proceeds. The amount of any potential settlement related to the trust and reduction in net proceeds is not presently determinable, but, in XTO Energy management's opinion, is not currently expected to be material to the trust's annual distributable income, financial position or liquidity. A second lawsuit, United States of America ex rel. Grynberg v. Cross Timbers Oil Company, et al., was filed in the United States District Court for the Western District of Oklahoma. This 10 action alleges that XTO Energy underpaid royalties on natural gas produced from federal leases and lands owned by Native Americans by at least 20% during the past ten years as a result of mismeasuring the volume of natural gas and wrongfully analyzing its heating content. The suit, which was brought under the QUI TAM provisions of the U.S. False Claims Act, seeks treble damages for the unpaid royalties (with interest), civil penalties between $5,000 and $10,000 for each violation of the U.S. False Claims Act, and an order for XTO Energy to cease the allegedly improper measuring practices. The cases against XTO Energy and other defendants have been consolidated in the United States District Court for Wyoming. While XTO Energy is unable to predict the outcome of this case or estimate the amount of any possible loss, it believes that the allegations of this lawsuit are without merit and intends to vigorously defend the action. However, an order to change measuring practices or a related settlement could adversely affect the trust by reducing net proceeds in the future by an amount that is presently not determinable, but, in XTO Energy management's opinion, is not currently expected to be material to the trust's annual distributable income, financial position or liquidity. In June 2001, XTO Energy was served with a third lawsuit styled Quinque Operating Co., et al. v. Gas Pipelines, et al. The action was filed in the District Court of Stevens County, Kansas, against XTO Energy and one of its subsidiaries, along with over 200 natural gas transmission companies, producers, gatherers and processors of natural gas. Plaintiffs sought to represent a class of plaintiffs consisting of all similarly situated royalty owners, overriding royalty owners and working interest owners either from whom defendants had purchased natural gas or who received economic benefit from the sale of such gas since January 1, 1974. The complaint alleged that the defendants had mismeasured both the volume and heating content of natural gas delivered into their pipelines resulting in underpayments to plaintiffs. The plaintiffs dismissed XTO Energy and its subsidiary as a defendant and substituted another subsidiary of XTO Energy as a defendant. Any potential liability of the subsidiary will not affect the trust's net proceeds. For further information regarding these lawsuits and other legal proceedings pertaining to the trust, see Item 3 of the trust's Annual Report on Form 10-K included in this report. 8. 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 included in this report. 9. QUARTERLY FINANCIAL DATA (UNAUDITED) The following is a summary of net profits income, distributable income and distributable income per unit by quarter for 2001 and 2000:

11 REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS BANK OF AMERICA, N.A., AS TRUSTEE FOR THE HUGOTON ROYALTY TRUST: We have audited the accompanying statements of assets, liabilities and trust corpus of the Hugoton Royalty Trust as of December 31, 2001 and 2000, and the statements of distributable income and changes in trust corpus for each of the years then ended. These financial statements are the responsibility of the trustee. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by the trustee, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. As described in Note 2 to the financial statements, these financial statements were prepared on the modified cash basis of accounting, which is a comprehensive basis of accounting other than accounting principles generally accepted in the United States. In our opinion, the financial statements referred to above present fairly, in all material respects, the assets, liabilities and trust corpus of the trust as of December 31, 2001 and 2000 and its distributable income and changes in trust corpus for each of the years then ended, in conformity with the modified cash basis of accounting described in Note 2. ARTHUR ANDERSEN LLP Fort Worth, Texas March 19, 2002 12 HUGOTON ROYALTY TRUST 901 Main Street, 17th Floor P.O. Box 830650 Dallas, Texas 75283-0650 (877) 228-5083 Bank of America, N.A., Trustee A copy of the Hugoton 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. AUDITORS Arthur Andersen LLP Fort Worth, Texas LEGAL COUNSEL Thompson & Knight L.L.P. Dallas, Texas TAX COUNSEL Winstead Sechrest & Minick P.C. Houston, Texas TRANSFER AGENT AND REGISTRAR Mellon Investor Services, L.L.C. Dallas, Texas www.melloninvestor.com EX-23.1 4 a2073906zex-23_1.txt EXHIBIT 23.1 EXHIBIT 23.1 INDEPENDENT PUBLIC ACCOUNTANTS' CONSENT Hugoton Royalty Trust Dallas, Texas As independent public accountants, we hereby consent to the incorporation by reference in the Registration Statements Nos. 333-81849 and 333-35830 on Form S-8 of XTO Energy Inc. of our report dated March 19, 2002, included in the Annual Report on Form 10-K of Hugoton Royalty Trust for the year ended December 31, 2001. ARTHUR ANDERSEN LLP Fort Worth, Texas March 27, 2002 EX-23.2 5 a2073906zex-23_2.txt EXHIBIT 23.2 EXHIBIT 23.2 [LETTERHEAD OF MILLER AND LENTS, LTD. APPEARS HERE] March 27, 2002 Hugoton Royalty Trust P.O. Box 830650 Dallas, TX 75283-0650 Re: Hugoton Royalty Trust 2001 Annual Report on Form 10-K Gentlemen: The firm of Miller and Lents, Ltd., consents to the use of its name and to the use of its report dated March 22, 2002, regarding the Hugoton Royalty Trust Proved Reserves and Future Net Revenue as of January 1, 2002, in the 2001 Annual Report on Form 10-K. Miller and Lents, Ltd., has no interests in the Hugoton Royalty Trust or in any affiliated companies or subsidiaries and is not to receive any such interest as payment for such reports and has no director, officer, or employee otherwise connected with Hugoton Royalty Trust. We are not employed by Hugoton Royalty Trust on a contingent basis. Yours very truly, MILLER AND LENTS, LTD. By /s/ James C. Pearson ----------------------------- James C. Pearson Chairman EX-99.1 6 a2073906zex-99_1.txt EXHIBIT 99.1 EXHIBIT 99.1 [LETTERHEAD OF BANK OF AMERICA APPEARS HERE] March 27, 2002 Securities and Exchange Commission 450 Fifth Street, NW Washington, DC 20549 Ladies and Gentlemen: Arthur Andersen LLP (Andersen) has audited the financial statements of Hugoton Royalty Trust as of December 31, 2001, and Andersen has represented to Bank of America, N.A., Trustee, that: - the audit was subject to Andersen's quality control system for the U.S. accounting and auditing practice to provide reasonable assurance that the engagement was conducted in compliance with professional standards, and - there was appropriate continuity of Arthur Andersen personnel working on the audit, and - there was availability of national office consultation to conduct the relevant portions of the audit. Sincerely, /s/ RON E. HOOPER - --------------------------- Ron E. Hooper Senior Vice President -----END PRIVACY-ENHANCED MESSAGE-----