UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

Form 10-Q

 

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

 

For the quarterly period ended June 30, 2002

 

OR

 

o	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 incorporation or organization)		(I.R.S. Employer 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:

 

 

 

HUGOTON ROYALTY TRUST

 

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

 

	TABLE OF CONTENTS	Page
	Glossary of Terms	3
PART I.	FINANCIAL INFORMATION
Item 1.	Financial Statements	4
	Independent Accountants’ Review Report	5
	Condensed Statements of Assets, Liabilities and Trust Corpus at June 30, 2002 and December 31, 2001	6
	Condensed Statements of Distributable Income for the Three and Six Months Ended June 30, 2002 and 2001	7
	Condensed Statements of Changes in Trust Corpus for the Three and Six Months Ended June 30, 2002 and 2001	8
	Notes to Condensed Financial Statements	9
Item 2.	Trustee’s Discussion and Analysis	11
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	15
PART II.	OTHER INFORMATION
Item 6.	Exhibits and Reports on Form 8-K	16
	Signatures	17

 

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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

 

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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 June 30, 2002 and the distributable income and changes in trust corpus for the three- and six-month periods ended June 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 six-month periods ended June 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.

 

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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 June 30, 2002 and the related condensed statements of distributable income and changes in trust corpus for the three- and six-month periods ended June 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 generally accepted auditing standards, 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.

 

 

KPMG LLP

 

Dallas, Texas

August 5, 2002

 

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HUGOTON ROYALTY TRUST

 

Condensed Statements of Assets, Liabilities and Trust Corpus

 

		June 30, 2002			December 31, 2001
		(Unaudited)
ASSETS
Cash and short-term investments		$	3,011,400		$	1,781,800
Net profits interests in oil and gas properties - net		210,792,482			215,346,192
		$	213,803,882		$	217,127,992
LIABILITIES AND TRUST CORPUS
Distribution payable to unitholders		$	3,011,400		$	1,781,800
Trust corpus (40,000,000 units of beneficial interest authorized and outstanding)		210,792,482			215,346,192
		$	213,803,882		$	217,127,992

 

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

 

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HUGOTON ROYALTY TRUST

 

Condensed Statements of Distributable Income (Unaudited)

 

		Three Months Ended June 30						Six Months Ended June 30
		2002			2001			2002			2001
Net profits income		$	5,560,186		$	21,720,948		$	12,972,606		$	55,404,820
Interest income		2,352			53,998			6,079			104,321
Total income		5,562,538			21,774,946			12,978,685			55,509,141
Administration expense		227,898			43,306			291,405			123,021
Distributable income		$	5,334,640		$	21,731,640		$	12,687,280		$	55,386,120
Distributable income per unit (40,000,000 units)		$	0.133366		$	0.543291		$	0.317182		$	1.384653

 

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

 

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HUGOTON ROYALTY TRUST

 

Condensed Statements of Changes in Trust Corpus (Unaudited)

 

		Three Months Ended June 30						Six Months Ended June 30
		2002			2001			2002			2001
Trust corpus, beginning of period		$	212,736,627		$	222,760,307		$	215,346,192		$	226,081,443
Amortization of net profits interests		(1,944,145		)	(2,577,103		)	(4,553,710		)	(5,898,239		)
Distributable income		5,334,640			21,731,640			12,687,280			55,386,120
Distributions declared		(5,334,640		)	(21,731,640		)	(12,687,280		)	(55,386,120		)
Trust corpus, end of period		$	210,792,482		$	220,183,204		$	210,792,482		$	220,183,204

 

 

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

 

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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., 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 $36,274,469 as of June 30, 2002 and $31,720,759 as of December 31, 2001.

 

2.             Development Costs

 

Cumulative actual development costs exceeded the amount deducted in the calculation of net profits income by $4.8 million as of December 31, 2001 and by $200,000 at March 31, 2002.  In calculating net profits income, XTO Energy deducted budgeted development costs of $5.8 million for the quarter and $11.6 million for the six months ended June 30, 2002.  After considering actual development costs of $4.4 million for the quarter and $5.6 million for the six-month period, cumulative actual development costs were $1.2 million less than the amount deducted as of June 30, 2002.  As of the July 2002 distribution,

 

9

 

cumulative actual development costs were $1 million less than the amount deducted.  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 estimated development budget for 2002 and drilling 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 court has ordered that the parties enter mediation, which is expected to occur in 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, 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.

 

10

 

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 June 30, 2002 net profits income was $5,560,186, as compared to $21,720,948 for second quarter 2001.  This 74% decline in net profits income is primarily the result of lower gas prices.  See “Net Profits Income” below.

 

After adding interest income of $2,352 and deducting administration expense of $227,898, distributable income for the quarter ended June 30, 2002 was $5,334,640, or $0.133366 per unit of beneficial interest.  Administration expense increased $184,592 from the prior year quarter, while interest income decreased $51,646.  The significant increase in administration expense for the quarter was primarily because of increased stock exchange listing fees and the timing of expenditures.  Decreased interest income over these periods was primarily because of the decline in net profits income and interest rates.  For second quarter 2001, distributable income was $21,731,640, or $0.543291 per unit.  Distributions to unitholders for the quarter ended June 30, 2002 were:

 

 

Six Months

 

For the six months ended June 30, 2002, net profits income was $12,972,606, compared with $55,404,820 for the same 2001 period.  This 77% decrease in net profits income is primarily the result of lower gas prices.

 

After adding interest income of $6,079 and deducting administration expense of $291,405, distributable income for the six months ended June 30, 2002 was $12,687,280, or $0.317182 per unit of beneficial interest.  Administration expense for the first six months of 2002 was significantly higher than in the first half of 2001 because of increased stock exchange listing fees and the timing of expenditures.  Interest income decreased over these periods primarily because of the decrease in net profits income and interest rates.  For the six months ended June 30, 2001, distributable income was $55,386,120, or $1.384653 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.

11

 

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

 

		Three Months Ended June 30 (a)						Increase			Six Months Ended June 30 (a)						Increase
		2002			2001			(Decrease)			2002			2001			(Decrease)
Sales Volumes
Gas (Mcf) (b)
Underlying properties		8,286,379			8,705,314			(5	%)		17,313,790			17,896,066			(3	%)
Average per day		93,105			97,813			(5	%)		95,656			98,873			(3	%)
Net profits interests		2,323,355			4,242,301			(45	%)		5,441,622			9,709,417			(44	%)
Oil (Bbls) (b)
Underlying properties		88,345			101,587			(13	%)		178,452			197,685			(10	%)
Average per day		993			1,141			(13	%)		986			1,092			(10	%)
Net profits interests		22,141			47,586			(53	%)		56,827			103,210			(45	%)
Average Sales Prices
Gas (per Mcf)		$ 2.25			$ 5.33			(58	%)		$ 2.31			$ 5.84			(60	%)
Oil (per Bbl)		$ 22.27			$ 28.37			(22	%)		$ 20.52			$ 29.38			(30	%)
Revenues
Gas sales		$ 18,606,779			$ 46,430,124			(60	%)		$ 40,052,036			$ 104,455,405			(62	%)
Oil sales		1,967,015			2,882,422			(32	%)		3,661,450			5,807,130			(37	%)
Total Revenues		20,573,794			49,312,546			(58	%)		43,713,486			110,262,535			(60	%)
Costs
Taxes, transportation and other		1,877,891			5,022,857			(63	%)		3,568,366			10,312,101			(65	%)
Production expense (c)		4,022,761			4,264,707			(6	%)		8,424,334			8,676,812			(3	%)
Development costs (d)		5,783,334			10,960,343			(47	%)		11,566,667			18,592,276			(38	%)
Overhead		1,999,575			1,913,454			5	%		3,998,361			3,733,145			7	%
Total Costs		13,683,561			22,161,361			(38	%)		27,557,728			41,314,334			(33	%)
Other Proceeds
Property sales		60,000			—			—			60,000			307,824			(81	%)
Net Proceeds		6,950,233			27,151,185			(74	%)		16,215,758			69,256,025			(77	%)
Net Profits Percentage		80		%	80		%				80		%	80		%
Net Profits Income		$	5,560,186		$	21,720,948		(74	%)		$	12,972,606		$	55,404,820		(77	%)

(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 June 30 generally represent production for the period February through April and (2) oil and gas sales for the six months ended June 30 generally represent production for the period November through April.

(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 2 to Financial Statements.

12

 

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

 

Sales Volumes

 

Gas

 

Second quarter gas sales volumes decreased 5% and year-to-date volumes decreased 3% primarily because of natural production decline, and gathering line and compressor downtime in Wyoming, partially offset by increased production from new wells and workovers in Oklahoma.

 

Oil

 

Oil sales volumes were 13% lower for the second quarter and 10% lower for the six-month period because of natural production decline and timing of cash receipts, partially offset by increased production from new wells and workovers in Oklahoma.

 

Sales Prices

 

Gas

 

The second quarter 2002 average gas price was $2.25 per Mcf, a 58% decrease from the second quarter 2001 average gas price of $5.33. 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 increased slightly during second quarter 2002.  The average NYMEX gas price for May through July 2002 was $3.26 per MMBtu.  Continuing mild weather and a weak economy have further reduced demand, causing current NYMEX prices again to drop below $3.00.  At August 1, 2002, the average NYMEX futures price for the following twelve months was $3.39 per MMBtu.  Gas prices are expected to remain volatile.  Trust gas prices related to the July 2002 distribution averaged approximately $0.70 per Mcf lower than the NYMEX price.  This differential increased from the spread of approximately $0.25 per Mcf for first quarter production primarily because of lower Wyoming prices related to pipeline constraints and reduced West Coast demand.

 

Oil

 

The average oil price for the second quarter decreased 22% to $22.27 per Bbl and for the six-month period decreased 30% to $20.52.  Trust oil prices were significantly higher in the first half 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 half of 2002, and in June 2002, announced it would maintain the production cut through September 2002.  Oil prices have shown some strengthening during 2002, but are expected to remain volatile.  The average NYMEX oil price for May through July 2002 was $26.52 per Bbl.  At August 1, 2002, the average NYMEX futures price for the following twelve months was $25.20.  Recent trust oil prices have averaged approximately $1.00 lower than the NYMEX price.

 

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Costs

 

Taxes

 

Taxes, transportation and other decreased 63% for the quarter and 65% for the six-month period, generally corresponding with reduced revenues.

 

Production

 

Production expense decreased 6% for the quarter and 3% for the six-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 47% for the second quarter and 38% for the six-month period because of reduced drilling activity at the end of 2001.  During the first half of 2002, six wells were completed on the underlying properties, and five were pending completion at June 30.  XTO Energy plans to drill eight more wells during 2002, all in western Oklahoma.

 

Cumulative actual development costs exceeded the amount deducted in the calculation of net profits income by $4.8 million as of December 31, 2001 and by $200,000 at March 31, 2002.  In calculating net profits income, XTO Energy deducted budgeted development costs of $5.8 million for the quarter and $11.6 million for the six months ended June 30, 2002.  After considering actual development costs of $4.4 million for the quarter and $5.6 million for the six-month period, cumulative actual development costs were $1.2 million less than the amount deducted as of June 30, 2002.  As of the July 2002 distribution, cumulative actual development costs were $1 million less than the amount deducted.  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 estimated development budget for 2002 and drilling to date.

 

Overhead

 

Overhead increased 5% for the quarter and 7% for the six-month period because of an increased well count, partially offset by a decreased annual rate adjustment during the second quarter based on an industry index.

 

Other Proceeds

 

Net profits income for the quarter and six months ended June 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 six months ended June 30, 2001 includes proceeds of $307,824 ($246,259 net to the trust) from the sale of certain underlying properties in Sweetwater County, Wyoming.

 

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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, 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 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.

 

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.

 

15

 

PART II - OTHER INFORMATION

 

Items 1 through 5.    Not applicable.

 

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

 

(a)  Exhibits.

 

Exhibit Number and Description		Page
(15)	Awareness letter of KPMG LLP	18
(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)

 

(b)  Reports on Form 8-K.

 

On June 28, 2002, the trust filed a report on Form 8-K dated June 25, 2002, to report its appointment of KPMG LLP as the trust’s independent auditors for fiscal 2002 to replace Arthur Andersen LLP, effective with such appointment.

 

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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	/s/NANCY G. WILLIS
		Nancy G. Willis
		Assistant Vice President
	XTO ENERGY INC.
Date: August 14, 2002	By	/s/LOUIS G. BALDWIN
		Louis G. Baldwin
		Executive Vice President
		and Chief Financial Officer

 

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