HUGOTON ROYALTY TRUST - Quarter Report: 2004 September (Form 10-Q)

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 September 30, 2004

		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 by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act). Yes ý No o

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

		Outstanding as of October 1, 2004
	40,000,000

HUGOTON ROYALTY TRUST

FORM 10-Q FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2004

TABLE OF CONTENTS

	Glossary of Terms

PART I.	FINANCIAL INFORMATION

Item 1.	Financial Statements

	Report of Independent Registered Public Accounting Firm

	Condensed Statements of Assets, Liabilities and Trust Corpus at September 30, 2004 and December 31, 2003

	Condensed Statements of Distributable Income for the Three and Nine Months Ended September 30, 2004 and 2003

	Condensed Statements of Changes in Trust Corpus for the Three and Nine Months Ended September 30, 2004 and 2003

	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

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, 2004 and the distributable income and changes in trust corpus for the three- and nine-month periods ended September 30, 2004 and 2003 have been included. Distributable income for such interim periods is not necessarily indicative of the distributable income for the full year.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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, 2004 and the related condensed statements of distributable income and changes in trust corpus for the three- and nine-month periods ended September 30, 2004 and 2003. These condensed financial statements are the responsibility of the trustee.

We conducted our review in accordance with standards established by the Public Company Accounting Oversight Board (United States). 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 the standards of the Public Company Accounting Oversight Board (United States), 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.

We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the statement of assets, liabilities and trust corpus of the Hugoton Royalty Trust as of December 31, 2003, and the related statements of distributable income and changes in trust corpus for the year then ended (not presented herein), included in the trust’s 2003 Annual Report on Form 10-K, and in our report dated March 5, 2004, we expressed an unqualified opinion on those financial statements. In our opinion, the information set forth in the accompanying condensed statement of assets, liabilities and trust corpus as of December 31, 2003 is fairly stated, in all material respects, in relation to the statement of assets, liabilities and trust corpus included in the trust’s 2003 Annual Report on Form 10-K from which it has been derived.

KPMG LLP

Dallas, Texas

October 15, 2004

HUGOTON ROYALTY TRUST

Condensed Statements of Assets, Liabilities and Trust Corpus

	September 30, 2004		December 31, 2003
	(Unaudited)
ASSETS

Cash and short-term investments	$	8,212,240	$	5,706,240

Net profits interests in oil and gas properties - net	185,192,132		193,245,847

	$	193,404,372	$	198,952,087

LIABILITIES AND TRUST CORPUS

Distribution payable to unitholders	$	8,212,240	$	5,706,240

Trust corpus (40,000,000 units of beneficial interest authorized and outstanding)	185,192,132		193,245,847

	$	193,404,372	$	198,952,087

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
	2004		2003		2004		2003

Net profits income	$	23,521,511	$	21,446,124	$	60,868,299	$	62,539,606

Interest income	9,303		7,511		20,156		22,623

Total income	23,530,814		21,453,635		60,888,455		62,562,229

Administration expense	101,974		75,555		304,295		280,549

Distributable income	$	23,428,840	$	21,378,080	$	60,584,160	$	62,281,680

Distributable income per unit (40,000,000 units)	$	0.585721	$	0.534452	$	1.514604	$	1.557042

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
	2004			2003			2004			2003

Trust corpus, beginning of period	$	188,000,381		$	199,282,415		$	193,245,847		$	205,493,243

Amortization of net profits interests	(2,808,249		)	(3,141,580		)	(8,053,715		)	(9,352,408		)

Distributable income	23,428,840			21,378,080			60,584,160			62,281,680

Distributions declared	(23,428,840		)	(21,378,080		)	(60,584,160		)	(62,281,680		)

Trust corpus, end of period	$	185,192,132		$	196,140,835		$	185,192,132		$	196,140,835

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 XTO Energy Inc., the owner of the underlying properties, 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. This comprehensive basis of accounting other than GAAP corresponds to the accounting permitted for royalty trusts by the U.S. Securities and Exchange Commission, as specified by Staff Accounting Bulletin Topic 12:E, Financial Statements of Royalty Trusts.

Most accounting pronouncements apply to entities whose financial statements are prepared in accordance with GAAP, directing such entities to accrue or defer revenues and expenses in a period other than when such revenues were received or expenses were paid. Because the trust’s financial statements are prepared on the modified cash basis, as described above, most accounting pronouncements are not applicable to the trust’s financial statements.

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 $61,874,819 as of September 30, 2004 and $53,821,104 as of December 31, 2003.

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
	2004			2003			2004			2003
Cumulative development costs (over) under the amount deducted - beginning of period	$	1,420,005		$	3,963,563		$	(1,583,988	)	$	3,089,563
Actual development costs	(3,757,300		)	(4,286,514		)	(10,953,307		)	(9,961,857		)
Development costs deducted	5,100,000			2,250,000			15,300,000			8,799,343
Cumulative development costs under the amount deducted - end of period	$	2,762,705		$	1,927,049		$	2,762,705		$	1,927,049

XTO Energy has informed the trustee that it plans to drill an additional five wells on the underlying properties in Oklahoma by year end. As a result, the monthly development cost deduction is increasing from $1,700,000 to $2,000,000 beginning with the October 2004 distribution. This increased monthly deduction is expected to be maintained through the March 2005 distribution. This deduction will be evaluated and revised as necessary.

3. Contingencies

Litigation

XTO Energy is a defendant in lawsuits related to the underlying properties that could, if adversely determined, decrease future trust distributable income attributable to production on or after December 1, 1998, the creation date of the trust. Any damages relating to production prior to December 1, 1998 will be borne by XTO Energy.

On October 17, 1997, an action, styled 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 by Jack J. Grynberg on behalf of the United States under the qui tam provisions of the U.S. False Claims Act against XTO Energy. The plaintiff alleges that XTO Energy underpaid royalties on natural gas produced from federal leases and lands owned by Native Americans in amounts in excess of 20% as a result of mismeasuring the volume of natural gas, incorrectly analyzing its heating content and improperly valuing the natural gas during at least the past ten years. The plaintiff seeks treble damages for the unpaid royalties (with interest, attorneys fees and expenses), 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. This lawsuit against XTO Energy and similar lawsuits filed by Grynberg against more than 300 other companies have been consolidated in the United States District Court for Wyoming. In October 2002, the court granted a motion to dismiss Grynberg’s royalty valuation claims, and Grynberg’s appeal of this decision was dismissed for lack of appellate jurisdiction in May 2003. The parties have completed discovery regarding whether the plaintiff has met the jurisdictional prerequisites for maintaining an action under the U.S. False Claims Act. In June 2004, XTO Energy joined with other defendants in filing a motion to dismiss, contending that the plaintiff has not satisfied the jurisdictional requirements to maintain this action. A hearing on this motion has not been scheduled. 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.

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.

Other

Several states have enacted legislation to require state income tax withholding from nonresident recipients of oil and gas proceeds. After consultation with its state tax counsel, XTO Energy has advised the trustee that it believes the trust is not subject to these withholding requirements. However, regulations are being developed or are subject to change by the various states, which could change this conclusion. In the event it is determined that the trust is required to withhold state taxes, distributions to the unitholders would be reduced by the required amount, subject to the unitholder’s right to file a state tax return to claim any refund due.

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 2003 annual report, as well as the condensed financial statements and notes thereto included in this quarterly report on Form 10-Q. The trust’s Annual Report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and all amendments to those reports are available on the trust’s web site at www.hugotontrust.com.

Distributable Income

Quarter

For the quarter ended September 30, 2004 net profits income was $23,521,511, as compared to $21,446,124 for third quarter 2003. Increased net profits income is primarily the result of higher product prices, partially offset by higher development costs. See “Net Profits Income” on the following page.

After adding interest income of $9,303 and deducting administration expense of $101,974, distributable income for the quarter ended September 30, 2004 was $23,428,840, or $0.585721 per unit of beneficial interest. Administration expense for the quarter increased 35% from the prior year quarter primarily because of the timing of expenditures. For third quarter 2003, distributable income was $21,378,080, or $0.534452 per unit. Distributions to unitholders for the quarter ended September 30, 2004 were:

Record Date	Payment Date	Distribution per Unit

July 30, 2004	August 13, 2004	$	0.183128
August 31, 2004	September 15, 2004	0.197287
September 30, 2004	October 15, 2004	0.205306
		$	0.585721

Nine Months

For the nine months ended September 30, 2004, net profits income was $60,868,299, compared with $62,539,606 for the same 2003 period. This 3% decrease in net profits income is primarily the result of increased development costs and lower sales volumes, partially offset by higher product prices. See “Net Profits Income” on the following page.

After adding interest income of $20,156 and deducting administration expense of $304,295, distributable income for the nine months ended September 30, 2004 was $60,584,160, or $1.514604 per unit of beneficial interest. Administration expense for the first nine months of 2004 was 8% higher than in the first nine months of 2003 primarily because of increased costs and the timing of expenditures. For the nine months ended September 30, 2003, distributable income was $62,281,680, or $1.557042 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
	2004		2003		(Decrease)	2004		2003		(Decrease)
Sales Volumes
Gas (Mcf) (b)
Underlying properties	7,610,566		7,819,586		(3)%	22,731,973		23,729,807		(4)%
Average per day	82,724		84,996		(3)%	82,963		86,922		(5)%
Net profits interests	4,323,048		4,574,284		(5)%	12,397,898		13,617,199		(9)%

Oil (Bbls) (b)
Underlying properties	82,513		76,978		7%	240,365		247,238		(3)%
Average per day	897		837		7%	877		906		(3)%
Net profits interests	47,015		44,048		7%	138,137		143,332		(4)%

Average Sales Prices
Gas (per Mcf)	$5.50		$4.82		14%	$4.96		$4.60		8%
Oil (per Bbl)	$38.59		$29.58		30%	$35.30		$30.31		16%

Revenues
Gas sales	$41,844,270		$37,714,470		11%	$112,657,193		$109,228,702		3%
Oil sales	3,183,986		2,277,397		40%	8,484,473		7,492,983		13%

Total Revenues	45,028,256		39,991,867		13%	121,141,666		116,721,685		4%

Costs
Taxes, transportation and other	3,819,435		3,529,346		8%	10,330,456		10,314,016		—
Production expense	4,666,777		4,544,674		3%	13,772,433		12,656,132		9%
Development costs (c)	5,100,000		2,250,000		127%	15,300,000		8,799,343		74%
Overhead	2,040,155		1,819,361		12%	5,653,403		5,737,338		(1)%
Litigation	—		1,040,831		(100)%	—		1,040,831		(100)%

Total Costs	15,626,367		13,184,212		19%	45,056,292		38,547,660		17%

Other Proceeds
Property sales	—		—		—	—		482		(100)%

Net Proceeds	29,401,889		26,807,655		10%	76,085,374		78,174,507		(3)%

Net Profits Percentage	80	%	80	%		80	%	80	%

Net Profits Income	$23,521,511		$21,446,124		10%	$60,868,299		$62,539,606		(3)%

(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 Condensed Financial Statements.

The following are explanations of significant variances from third quarter 2003 to third quarter 2004 and from the first nine months of 2003 to the comparable period in 2004:

Sales Volumes

Gas

Gas sales volumes decreased 3% for third quarter 2004 and 4% for the nine-month period as compared with the same 2003 periods. The decrease is primarily because of natural production decline, partially offset by increased production from new wells and workovers.

Oil

Oil sales volumes increased 7% for third quarter 2004 and decreased 3% for the nine-month period as compared with the same 2003 periods. New wells and workovers, including a fracturing project on one of the underlying properties in Kansas, resulted in increased volumes for the quarter. Natural decline was largely offset by the effects of new wells and workovers in the nine-month period.

Sales Prices

Gas

The third quarter 2004 average gas price was $5.50 per Mcf, a 14% increase from the third quarter 2003 average gas price of $4.82 per Mcf. For the nine-month period, the average gas price increased 8% to $4.96 per Mcf in 2004 from $4.60 per Mcf in 2003. Colder than normal weather, record low gas storage levels and continued increasing demand caused gas prices to remain relatively high during the first five months of 2003. With diminished demand related to higher prices, natural gas prices were lower during the summer months, then rose with cooler weather in the fall and early winter. Forecasts for continued production declines, increasing natural gas demand and larger than projected storage withdrawals supported higher prices in the first six months of 2004. Mild summer weather and increased gas storage inventories led to declining gas prices in August and early September. Natural gas prices rose again in mid-September because of reduced gas production as a result of hurricanes in the Gulf of Mexico. Prices will continue to be affected by weather, the recovery of the domestic economy, increases in the level of North American production and import levels of liquified natural gas. In any case, natural gas prices are expected to remain volatile. The third quarter 2004 gas price is primarily related to production from May through July 2004, when the average NYMEX price was $6.25 per MMBtu, or $0.63 higher than the comparable 2003 period average NYMEX price of $5.62 per MMBtu. The average NYMEX price for August and September 2004 was $5.31 per MMBtu. At October 15, 2004, the average NYMEX futures price for the following twelve months was $7.20 per MMBtu. Recent trust gas prices have averaged approximately $0.50 per MMBtu lower than the NYMEX price.

Oil

The third quarter 2004 average oil price was $38.59 per Bbl, a 30% increase from the third quarter 2003 average oil price of $29.58 per Bbl. The 2004 year-to-date average oil price increased 16% to $35.30 per Bbl from $30.31 per Bbl in the same 2003 period. Crude oil prices are generally determined by global supply and demand. During 2003, increased demand, continued uncertainties in the Middle East and production discipline by OPEC maintained oil prices at relatively high levels. Oil prices continued to increase in early 2004 because of increasing demand and low crude stocks. In June and July 2004, supply disruption concerns caused oil prices to exceed $40 per Bbl. OPEC members agreed to increase daily oil production by 2 million

barrels beginning July 2004 and an additional 500,000 barrels beginning August 2004 to maintain market stability and prices. Although OPEC recently decided to increase daily oil production by 1 million barrels beginning November 2004, oil prices have continued to increase. Continued instability in the Middle East, political unrest in Nigeria and hurricanes in the Gulf of Mexico led to record oil prices exceeding $50 per Bbl in October. The average NYMEX price for August and September 2004 was $45.34 per Bbl. At October 15, 2004, the average NYMEX futures price for the following twelve months was $51.00 per Bbl. Recent trust oil prices have averaged approximately $1.00 per Bbl lower than the NYMEX price.

Costs

Taxes

Taxes, transportation and other increased 8% for the quarter and remained flat for the nine-month period. In each period, increased production taxes and other deductions related to higher revenues were offset by decreased property taxes related to the timing of cash disbursements.

Production

Production expense increased 3% for the quarter and 9% for the nine-month period primarily because of increased maintenance, fuel and labor costs.

Development

Development costs deducted in the calculation of net profits income are based on the 2004 annual budget. These development costs increased 127% for the third quarter and 74% for the nine-month period because of the timing of development projects. During the first nine months of 2004, 12 wells were completed and 11 wells were pending completion on the underlying properties at September 30. XTO Energy has informed the trustee that it plans to drill an additional five wells in 2004 on the underlying properties in Oklahoma for an annual total of 30 wells. All 2004 drilling is expected to be in western Oklahoma and southwestern Wyoming.

As a result of the five additional wells to be drilled in 2004, XTO Energy increased the annual development cost budget from approximately $20 million to $22 million. Because of this, XTO Energy increased the monthly development cost deduction from $1.7 million to $2 million beginning with the October distribution. This increased monthly deduction is expected to be maintained through the March 2005 distribution, and will be evaluated and revised as necessary.

As of December 31, 2003, actual costs exceeded cumulative development costs deducted by $1.6 million. In calculating net profits income, XTO Energy deducted budgeted development costs of $5.1 million for the quarter and $15.3 million for the nine-month period. After considering actual development costs of $3.8 million for the quarter and $11 million for the nine-month period, cumulative development costs deducted exceeded actual development costs by $2.8 million at September 30, 2004. See Note 2 to Condensed Financial Statements.

Overhead

Overhead increased 12% for the quarter and decreased 1% for the nine-month period. Increased overhead for the quarter is primarily because of the annual rate adjustment based on an industry index and the timing of an annual Oklahoma administrative fee. Decreased overhead for the nine-month period is primarily because of adjustments related to prior periods in Wyoming, partially offset by the annual rate adjustment.

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 activities, development, production and other 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, 2003, 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 Part II, Item 7a of the trust’s Annual Report on Form 10-K for the year ended December 31, 2003.

Item 4. Controls and Procedures.

As of the end of the period covered by 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 Rules 13a-15 and 15d-15. Based upon that evaluation, the trustee concluded that the trust’s disclosure controls and procedures are effective in timely alerting the trustee to material information relating to the trust required to be included in the trust’s periodic filings with the Securities and Exchange Commission. In its evaluation of disclosure controls and procedures, the trustee has relied, to the extent considered reasonable, on information provided by XTO Energy. There has not been any change in the trust’s internal control over financial reporting during the period covered by this report that has materially affected, or is reasonably likely to materially affect, the trust’s internal control over financial reporting.

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

	(31)	Rule 13a-14(a)/15d-14(a) Certification

	(32)	Section 1350 Certification

	(99)	Items 7 and 7a to the Annual Report on Form 10-K for Hugoton Royalty Trust filed with the Securities and Exchange Commission on March 11, 2004 (incorporated herein by reference)

(b)		Reports on Form 8-K.

		No reports on Form 8-K were filed during the quarter. The trust furnished three reports on Form 8-K under Item 2.02 (or Item 12 prior to August 23, 2004) for this period.

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
		Vice President


	XTO ENERGY INC.


Date: October 19, 2004	By	/s/ Louis G. Baldwin
		Louis G. Baldwin
		Executive Vice President and Chief Financial Officer