HUGOTON ROYALTY TRUST - Quarter Report: 2002 September (Form 10-Q)

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2002

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934

Commission File Number: 1-10476

Hugoton Royalty Trust

(Exact name of registrant as specified in its charter)

Texas		58-6379215
(State or other jurisdiction of		(I.R.S. Employer
incorporation or organization)		Identification No.)

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

(877) 228-5083

(Registrant's telephone number, including area code)

NONE

(Former name, former address and former fiscal year, if change since last report)

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 ý No o

Indicate the number of units of beneficial interest outstanding, as of the latest practicable date:

Outstanding as of October 1, 2002

40,000,000

HUGOTON ROYALTY TRUST

FORM 10-Q FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2002



	TABLE OF CONTENTS



	Glossary of Terms

PART I.	FINANCIAL INFORMATION

Item 1.	Financial Statements

	Independent Accountants’ Review Report

	Condensed Statements of Assets, Liabilities and Trust Corpus
	at September 30, 2002 and December 31, 2001

	Condensed Statements of Distributable Income
	for the Three and Nine Months Ended September 30, 2002 and 2001

	Condensed Statements of Changes in Trust Corpus
	for the Three and Nine Months Ended September 30, 2002 and 2001

	Notes to Condensed Financial Statements

Item 2.	Trustee’s Discussion and Analysis

Item 3.	Quantitative and Qualitative Disclosures about Market Risk

Item 4.	Controls and Procedures

PART II.	OTHER INFORMATION

Item 1.	Legal Proceedings

Item 6.	Exhibits and Reports on Form 8-K

	Signatures

	Trustee Certifications

HUGOTON ROYALTY TRUST

GLOSSARY OF TERMS

The following are definitions of significant terms used in this Form 10-Q:

Bbl Barrel (of oil)

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% and paid to the trust by XTO Energy. “Net profits income” is referred to as “royalty income” for income tax purposes.

net profits interest An interest in an oil and gas property measured by net profits from the sale of production, rather than a specific portion of production. The following defined net profits interests were conveyed to the trust from the underlying properties:

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

HUGOTON ROYALTY TRUST

PART I - FINANCIAL INFORMATION

Item 1. Financial Statements.

The condensed financial statements included herein are presented, without audit, pursuant to the rules and regulations of the Securities and Exchange Commission. Certain information and footnote disclosures normally included in annual financial statements have been condensed or omitted pursuant to such rules and regulations, although the trustee believes that the disclosures are adequate to make the information presented not misleading. These condensed financial statements should be read in conjunction with the trust’s financial statements and the notes thereto included in the trust’s annual report on Form 10-K. In the opinion of the trustee, all adjustments, consisting only of normal recurring adjustments, necessary to present fairly the assets, liabilities and trust corpus of the Hugoton Royalty Trust at September 30, 2002 and the distributable income and changes in trust corpus for the three- and nine-month periods ended September 30, 2002 and 2001 have been included. Distributable income for such interim periods is not necessarily indicative of the distributable income for the full year.

The financial data for the three- and nine-month periods ended September 30, 2002 included herein have been subjected to a limited review by KPMG LLP, the registrant’s independent accountants. The accompanying review report of independent accountants is not a report within the meaning of Sections 7 and 11 of the Securities Act of 1933 and the independent accountant’s liability under Section 11 does not extend to it. The trust’s financial statements for the year ended December 31, 2001 were audited by other independent accountants.

INDEPENDENT ACCOUNTANTS’ REVIEW REPORT

Bank of America, N.A., as Trustee

for the Hugoton Royalty Trust:

We have reviewed the accompanying condensed statement of assets, liabilities and trust corpus of the Hugoton Royalty Trust as of September 30, 2002 and the related condensed statements of distributable income and changes in trust corpus for the three- and nine-month periods ended September 30, 2002. These condensed financial statements are the responsibility of the trustee.

We conducted our review in accordance with standards established by the American Institute of Certified Public Accountants. A review of interim financial information consists principally of applying analytical procedures to financial data and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with auditing standards generally accepted in the United States of America, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.

The accompanying condensed financial statements are prepared on a modified cash basis as described in Note 1 which is a comprehensive basis of accounting other than accounting principles generally accepted in the United States of America.

Based on our review, we are not aware of any material modifications that should be made to the condensed financial statements referred to above for them to be in conformity with the basis of accounting described in Note 1.

The financial statements of Hugoton Royalty Trust as of and for the year ended December 31, 2001 were audited by other auditors who have ceased operations. Those auditors’ report, dated March 19, 2002, on those financial statements was unqualified, and included an explanatory paragraph that described the Trust's basis of accounting discussed in Note 2 to the financial statements. Such financial statements were not audited by us and, accordingly, we do not express an opinion or any form of assurance on the information set forth in the accompanying condensed statements of assets, liabilities and trust corpus as of December 31, 2001. Additionally, the condensed statements of distributable income for the three-month and nine-month periods ended September 30, 2001, and the related condensed statements of changes in trust corpus for the three-month and nine-month periods ended September 30, 2001, were not reviewed or audited by us and, accordingly, we do not express an opinion or any form of assurance on them.

KPMG LLP

Dallas, Texas

October 9, 2002

HUGOTON ROYALTY TRUST

Condensed Statements of Assets, Liabilities and Trust Corpus

	September 30, 2002		December 31, 2001
	(Unaudited)
ASSETS

Cash and short-term investments	$	2,523,240	$	1,781,800

Net profits interests in oil and gas properties - net	208,102,808		215,346,192

	$	210,626,048	$	217,127,992

LIABILITIES AND TRUST CORPUS

Distribution payable to unitholders	$	2,523,240	$	1,781,800

Trust corpus (40,000,000 units of beneficial interest
authorized and outstanding)	208,102,808		215,346,192

	$	210,626,048	$	217,127,992

The accompanying notes to condensed financial statements are an integral part of these statements.

HUGOTON ROYALTY TRUST

Condensed Statements of Distributable Income(Unaudited)

	Three Months Ended September 30				Nine Months Ended September 30
	2002		2001		2002		2001

Net profits income	$	8,670,968	$	15,359,771	$	21,643,574	$	70,764,591

Interest income	5,218		23,639		11,296		127,960

Total income	8,676,186		15,383,410		21,654,870		70,892,551

Administration expense	53,506		111,570		344,910		234,591

Distributable income	$	8,622,680	$	15,271,840	$	21,309,960	$	70,657,960

Distributable income per unit
(40,000,000 units)	$	0.215567	$	0.381796	$	0.532749	$	1.766449

The accompanying notes to condensed financial statements are an integral part of these statements.

HUGOTON ROYALTY TRUST

Condensed Statements of Changes in Trust Corpus (Unaudited)

	Three Months Ended September 30						Nine Months Ended September 30
	2002			2001			2002			2001

Trust corpus, beginning of period	$	210,792,482		$	220,183,204		$	215,346,192		$	226,081,443

Amortization of net profits interests	(2,689,674		)	(2,633,170		)	(7,243,384		)	(8,531,409		)

Distributable income	8,622,680			15,271,840			21,309,960			70,657,960

Distributions declared	(8,622,680		)	(15,271,840		)	(21,309,960		)	(70,657,960		)

Trust corpus, end of period	$	208,102,808		$	217,550,034		$	208,102,808		$	217,550,034

The accompanying notes to condensed financial statements are an integral part of these statements.

HUGOTON ROYALTY TRUST

Notes to Condensed Financial Statements (Unaudited)

1. Basis of Accounting

The financial statements of Hugoton Royalty 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 (“GAAP”):

– Net profits income recorded for a month is the amount computed and paid by the interest owner, XTO Energy Inc. (formerly named Cross Timbers Oil Company), to Bank of America, N.A., as trustee for the trust. Net profits income consists of net proceeds received by XTO Energy from the underlying properties in the prior month, multiplied by a net profits percentage of 80%.

Costs deducted in the calculation of net proceeds for the 80% net profits interests generally include applicable taxes, transportation, marketing and legal costs, production expenses, development costs, operating charges and other costs.

– Net profits income is computed separately for each of three conveyances under which the net profits interests were conveyed to the trust. If monthly costs exceed revenues for any conveyance, such excess costs must be recovered, with accrued interest, from future net proceeds of that conveyance and cannot reduce net proceeds from the other conveyances.

– 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.

The trust’s financial statements differ from those prepared in conformity with GAAP because revenues are recognized when received rather than accrued in the month of production, expenses are recognized when paid rather than when incurred and certain cash reserves may be established by the trustee for contingencies which would not be recorded under GAAP.

The initial carrying value of the net profits interests of $247,066,951 represents XTO Energy’s historical net book value for 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 $38,964,143 as of September 30, 2002 and $31,720,759 as of December 31, 2001.

2. Development Costs

The following summarizes actual development costs, the amount of development costs deducted in the calculation of net profits income and the cumulative actual development costs (over) under the amount deducted:

	Three Months Ended September 30						Nine Months Ended September 30
	2002			2001			2002			2001
Cumulative development costs (over)
under the amount deducted - beginning
of period	$	1,230,748		$	-		$	(4,778,880	)	$	-
Actual development costs	(5,934,607		)	(14,296,040		)	(11,491,646		)	(32,888,316		)
Amount deducted	5,783,333			6,300,000			17,350,000			24,892,276
Cumulative development costs (over)
under the amount deducted - end of
period	$	1,079,474		$	(7,996,040	)	$	1,079,474		$	(7,996,040	)

XTO Energy has advised the trustee that it will continue to deduct development costs at a rate of $1.9 million per month through the remainder of 2002 based on the development budget for 2002 and development activities to date.

3. 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 December 1, 1998, the creation date 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, formerly known as Cross Timbers Oil Company, 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 parties have entered into court-ordered mediation and are continuing to discuss the terms of a possible settlement. 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, 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% 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 has informed the trustee that 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.

Item 2. Trustee’s Discussion and Analysis.

The following discussion should be read in conjunction with the trustee’s discussion and analysis contained in the trust’s 2001 annual report, as well as the condensed financial statements and notes thereto included in this quarterly report on Form 10-Q.

Distributable Income

Quarter

For the quarter ended September 30, 2002, net profits income was $8,670,968, as compared to $15,359,771 for third quarter 2001. This 44% decline in net profits income is primarily the result of lower gas prices. See “Net Profits Income” below.

After adding interest income of $5,218 and deducting administration expense of $53,506, distributable income for the quarter ended September 30, 2002 was $8,622,680, or $0.215567 per unit of beneficial interest. Administration expense decreased $58,064 and interest income decreased $18,421 from the prior year quarter. The significant decrease in administration expense for the quarter was primarily due to timing of expenditures. Decreased interest income over these periods was caused by lower net profits income and interest rates. For third quarter 2001, distributable income was $15,271,840, or $0.381796 per unit. Distributions to unitholders for the quarter ended September 30, 2002 were:

Record Date	Payment Date	Distribution per Unit

July 31, 2002	August 14, 2002	$	0.086028
August 30, 2002	September 16, 2002	0.066458
September 30, 2002	October 15, 2002	0.063081

		$	0.215567

Nine Months

For the nine months ended September 30, 2002, net profits income was $21,643,574, compared with $70,764,591 for the same 2001 period. This 69% decrease in net profits income is primarily the result of lower gas prices. See “Net Profits Income” below.

After adding interest income of $11,296 and deducting administration expense of $344,910, distributable income for the nine months ended September 30, 2002 was $21,309,960, or $0.532749 per unit of beneficial interest. Administration expense increased significantly in the first nine months of 2002 because of increased stock exchange listing fees. Interest income decreased because of lower net profits income and interest rates. For the nine months ended September 30, 2001, distributable income was $70,657,960, or $1.766449 per unit.

Net Profits Income

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. Net profits income is generally affected by three major factors:

– oil and gas sales volumes,

– oil and gas sales prices, and

– costs deducted in the calculation of net profits income.

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

	Three Months Ended September 30 (a)				Increase	Nine Months Ended September 30 (a)				Increase
	2002		2001		(Decrease)	2002		2001		(Decrease)
Sales Volumes
Gas (Mcf) (b)
Underlying properties	8,589,343		9,180,576		(6%)	25,903,133		27,076,642		(4%)
Average per day	93,362		99,789		(6%)	94,883		99,182		(4%)
Net profits interests	3,214,095		4,334,262		(26%)	8,655,717		14,043,679		(38%)

Oil (Bbls) (b)
Underlying properties	91,717		100,983		(9%)	270,169		298,668		(10%)
Average per day	997		1,098		(9%)	990		1,094		(10%)
Net profits interests	34,849		48,814		(29%)	91,676		152,024		(40%)

Average Sales Prices
Gas (per Mcf)	$	2.60	$	3.51	(26%)	$	2.41	$	5.05	(52%)
Oil (per Bbl)	$	25.84	$	26.56	(3%)	$	22.32	$	28.42	(21%)

Revenues
Gas sales	$	22,329,685	$	32,243,373	(31%)	$	62,381,721	$	136,698,778	(54%)
Oil sales	2,369,659		2,681,943		(12%)	6,031,109		8,489,073		(29%)

Total Revenues	24,699,344		34,925,316		(29%)	68,412,830		145,187,851		(53%)

Costs
Taxes, transportation
and other	2,183,289		3,303,309		(34%)	5,751,655		13,615,410		(58%)
Production expense	3,832,095		4,155,715		(8%)	12,256,429		12,832,527		(4%)
Development costs (c)	5,783,333		6,300,000		(8%)	17,350,000		24,892,276		(30%)
Overhead	2,061,917		1,966,578		5%	6,060,278		5,699,723		6%

Total Costs	13,860,634		15,725,602		(12%)	41,418,362		57,039,936		(27%)

Other Proceeds
Property sales	-		-		-	60,000		307,824		(81%)

Net Proceeds	10,838,710		19,199,714		(44%)	27,054,468		88,455,739		(69%)

Net Profits Percentage	80%		80%			80%		80%

Net Profits Income	$	8,670,968	$	15,359,771	(44%)	$	21,643,574	$	70,764,591	(69%)

________________________

(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 quarter ended September 30 generally represent production for the period May through July and (2) oil and gas sales for the nine months ended September 30 generally represent production for the period November through July.

(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) See Note 2 to Financial Statements.

The following are explanations of significant variances from third quarter 2001 to third quarter 2002 and from the first nine months of 2001 to the comparable period in 2002:

Sales Volumes

Gas

Third quarter gas sales volumes decreased 6% and year-to-date volumes decreased 4% primarily because of natural production decline, partially offset by timing of cash receipts and increased production from new wells and workovers in Oklahoma.

Oil

Oil sales volumes were 9% lower for the third quarter and 10% lower for the nine-month period because of natural production decline, partially offset by timing of cash receipts and increased production from new wells and workovers in Oklahoma.

Sales Prices

Gas

Gas prices for the third quarter decreased 26% to $2.60 per Mcf and for the nine-month period decreased 52% to $2.41 per Mcf. Gas prices were unusually high at the beginning of 2001 as winter demand strained already low gas supplies. Prices subsequently declined and gas storage levels increased in 2001 because of fuel switching due to higher prices, milder weather and a weaker economy, which reduced demand for gas to generate electricity. Although the winter of 2001-2002 was one of the warmest on record with resulting higher than average storage levels, gas prices have generally increased during 2002. The average NYMEX gas price for August and September 2002 was $3.32 per MMBtu. Gas prices recently have increased because of the threat of interruption of gas supplies by hurricanes in the Gulf of Mexico. At October 15, 2002, the average NYMEX futures price for the following twelve months was $4.12 per MMBtu. Gas prices are expected to remain volatile. Recent trust gas prices have averaged approximately $0.90 per Mcf lower than the NYMEX price. This differential has widened from the spread of approximately $0.70 per Mcf for second quarter production primarily because of continued lower Wyoming prices related to pipeline constraints and reduced West Coast demand.

Oil

The average oil price for the third quarter decreased 3% to $25.84 per Bbl and for the nine-month period decreased 21% to $22.32. Trust oil prices were significantly higher in the first nine months of 2001 as a result of global demand outpacing supply at the end of 2000 and early in 2001. Lagging demand, resulting from a worldwide economic slowdown, caused oil prices to decline during the remainder of 2001. OPEC members agreed to cut daily production by one million barrels in April 2001 and an additional one million barrels in September 2001 to adjust for weak demand and excess supply. The economic decline was accelerated by the terrorist attacks in the U.S. on September 11, 2001, placing additional downward pressure on oil prices. OPEC cut an additional 1.5 million barrels per day for the first nine months of 2002, and in September 2002, announced it would maintain the production cut through December 2002. Oil prices have been higher in recent months because of rising tension in the Middle East. The average NYMEX oil price for August and September 2002 was $25.87 per Bbl. At October 15, 2002, the average NYMEX futures price for the

following twelve months was $27.45. Recent trust oil prices have averaged approximately $0.70 lower than the NYMEX price.

Costs

Taxes

Taxes, transportation and other decreased 34% for the quarter and 58% for the nine-month period, generally corresponding with reduced revenues.

Production

Production expense decreased 8% for the quarter and 4% for the nine-month period, primarily because of the timing of maintenance projects, billings and expenditures and decreased fuel costs related to lower gas prices.

Development

Development costs decreased 8% for the third quarter and 30% for the nine-month period because of lower drilling activity and lower prices for services and materials. During the first nine months of 2002, 11 wells were completed on the underlying properties, and three were pending completion at September 30. XTO Energy has advised the trustee that it plans to drill four more wells during 2002, all in western Oklahoma.

In calculating net profits income, XTO Energy deducted budgeted development costs of $5.8 million for the quarter and $17.4 million for the nine months ended September 30, 2002. After considering actual development costs of $5.9 million for the quarter and $11.5 million for the nine-month period, cumulative actual development costs were $1.1 million less than the amount deducted as of September 30, 2002. See Note 2 to Financial Statements. XTO Energy has advised the trustee that it will continue to deduct development costs at a rate of $1.9 million per month through the remainder of 2002 based on the development budget for 2002 and development activities to date.

Overhead

Overhead increased 5% for the quarter and 6% for the nine-month period because of an increased well count and the timing of an annual Oklahoma administrative fee, partially offset by a decreased annual rate adjustment during the second quarter based on an industry index.

Other Proceeds

Net profits income for the nine months ended September 30, 2002 includes proceeds of $60,000 ($48,000 net to the trust) from the sale of a property in Major County, Oklahoma. Net profits income for the nine months ended September 30, 2001 includes proceeds of $307,824 ($246,259 net to the trust) from the sale of certain underlying properties in Sweetwater County, Wyoming.

Forward-Looking Statements

This Form 10-Q 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 Form 10-Q, including, without limitation, statements regarding the net profits interests, underlying properties, development costs, oil and gas prices, future drilling plans and industry and market conditions, are forward-looking statements that are subject to risks and uncertainties which are detailed in Part II, Item 7 of the trust’s annual report on Form 10-K for the year ended December 31, 2001, which is incorporated by this reference as though fully set forth herein. Although XTO Energy and the trustee believe that the expectations reflected in such forward-looking statements are reasonable, neither XTO Energy nor the trustee can give any assurance that such expectations will prove to be correct.

Item 3. Quantitative and Qualitative Disclosures about Market Risk

There have been no material changes in the trust’s market risks, as disclosed in the trust’s Form 10-K for the year ended December 31, 2001.

Item 4. Controls and Procedures.

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

PART II - OTHER INFORMATION

Item 1. Legal Proceedings.

Items 2 through 5. Not applicable.

Item 6. Exhibits and Reports on Form 8-K.

(a) Exhibits.

	Exhibit Number
	and Description

	(15)	Awareness letter of KPMG LLP

	(99)	Item 7a. to the Annual Report on Form 10-K for Hugoton Royalty Trust filed with the Securities and Exchange Commission on March 27, 2002 (incorporated herein by reference)

	(99.1)	Trustee Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

(b) Reports on Form 8-K.

On August 14, 2002, the trust filed a report on Form 8-K dated August 14, 2002, to furnish the trustee’s certification of the trust’s Quarterly Report on Form 10-Q for the period ended June 30, 2002 as required by 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

SIGNATURES

Pursuant to the requirements 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	Nancy G. Willis
		Nancy G. Willis
		Assistant Vice President

	XTO ENERGY INC.

Date: October 25, 2002	By	Louis G. Baldwin
		Louis G. Baldwin
		Executive Vice President
		and Chief Financial Officer

CERTIFICATIONS

I, Nancy G. Willis, certify that on behalf of Bank of America, N.A., Trustee of Hugoton Royalty Trust that:

1. I have reviewed this quarterly report on Form 10-Q of Hugoton Royalty Trust;

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

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

4. I am responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and I have:

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

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

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

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

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

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

6. I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of my most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

	Bank of America, N.A.

Date: October 25, 2002	By	Nancy G. Willis
		Nancy G. Willis
		Assistant Vice President