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~~September 30, 2005

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 changed 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 by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No ý

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

Outstanding as of ~~July 15,~~October 1, 2005

40,000,000

HUGOTON ROYALTY TRUST

FORM 10-Q FOR THE QUARTERLY PERIOD ENDED ~~JUNE~~SEPTEMBER 30, 2005

	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 ~~June~~September 30, 2005 and December 31, 2004

	Condensed Statements of Distributable Income for the Three and ~~Six~~Nine Months Ended ~~June~~September 30, 2005 and 2004

	Condensed Statements of Changes in Trust Corpus for the Three and ~~Six~~Nine Months Ended ~~June~~September 30, 2005 and 2004

	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 6.	Exhibits

	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 Inc. from sale of production from the underlying properties, less applicable costs, as defined in the net profits interest conveyances

net profits income		Net proceeds multiplied by the net profits percentage of 80%, which is paid to the trust by XTO Energy Inc. “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 Inc.’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 expense 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 ~~June~~September 30, 2005 and the distributable income and changes in trust corpus for the three- and ~~six-month~~nine-month periods ended ~~June~~September 30, 2005 and 2004 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 ~~June~~September 30, 2005 and the related condensed statements of distributable income and changes in trust corpus for the three- and ~~six-month~~nine-month periods ended ~~June~~September 30, 2005 and 2004. 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, 2004, 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 2004 Annual Report on Form 10-K, and in our report dated March 14, 2005, 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, 2004 is fairly stated, in all material respects, in relation to the statement of assets, liabilities and trust corpus included in the trust’s 2004 Annual Report on Form 10-K from which it has been derived.

KPMG LLP

Dallas, Texas

~~July 19,~~October 21, 2005

HUGOTON ROYALTY TRUST

Condensed Statements of Assets, Liabilities and Trust Corpus

					September 30,		December 31,
	June 30, 2005		December 31, 2004		2005		2004
	(Unaudited)				(Unaudited)
ASSETS

Cash and short-term investments	$	8,746,880	$	6,947,520	$	8,808,240	$	6,947,520

Net profits interests in oil and gas properties - net (Note 1)	177,114,508		182,551,814		174,484,666		182,551,814

	$	185,861,388	$	189,499,334	$	183,292,906	$	189,499,334

LIABILITIES AND TRUST CORPUS

Distribution payable to unitholders	$	8,746,880	$	6,947,520	$	8,808,240	$	6,947,520

Trust corpus (40,000,000 units of beneficial interest authorized and outstanding)	177,114,508		182,551,814		174,484,666		182,551,814

	$	185,861,388	$	189,499,334	$	183,292,906	$	189,499,334

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
June 30

Six Months Ended
June 30

2005

2004

2005

2004

Net profits income

$
22,965,660

$
18,289,557

$
48,784,600

$
37,346,788

Interest income

21,859

6,751

41,909

10,853

Total income

22,987,519

18,296,308

48,826,509

37,357,641

Administration expense

155,479

117,748

296,309

202,321

Distributable income

$
22,832,040

$
18,178,560

$
48,530,200

$
37,155,320

Distributable income per unit (40,000,000 units)

$
0.570801

$
0.454464

$
1.213255

$
0.928883

~~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
June 30

Six Months Ended
June 30

2005

2004

2005

2004

Trust corpus, beginning of period

$
179,730,111

$
190,517,602

$
182,551,814

$
193,245,847

Amortization of net profits interests

(2,615,603
)
(2,517,221
)
(5,437,306
)
(5,245,466
)

Distributable income

22,832,040

18,178,560

48,530,200

37,155,320

Distributions declared

(22,832,040
)
(18,178,560
)
(48,530,200
)
(37,155,320
)

Trust corpus, end of period

$
177,114,508

$
188,000,381

$
177,114,508

$
188,000,381

	Three Months Ended				Nine Months Ended
	September 30				September 30
	2005		2004		2005		2004

Net profits income	$	24,325,921	$	23,521,511	$	73,110,521	$	60,868,299

Interest income	29,600		9,303		71,509		20,156

Total income	24,355,521		23,530,814		73,182,030		60,888,455

Administration expense	51,321		101,974		347,630		304,295

Distributable income	$	24,304,200	$	23,428,840	$	72,834,400	$	60,584,160

Distributable income per unit (40,000,000 units)	$	0.607605	$	0.585721	$	1.820860	$	1.514604

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						Nine Months Ended
	September 30						September 30
	2005			2004			2005			2004

Trust corpus, beginning of period	$	177,114,508		$	188,000,381		$	182,551,814		$	193,245,847

Amortization of net profits interests	(2,629,842		)	(2,808,249		)	(8,067,148		)	(8,053,715		)

Distributable income	24,304,200			23,428,840			72,834,400			60,584,160

Distributions declared	(24,304,200		)	(23,428,840		)	(72,834,400		)	(60,584,160		)

Trust corpus, end of period	$	174,484,666		$	185,192,132		$	174,484,666		$	185,192,132

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 Inc. 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 expense, 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 Inc.’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 ~~$69,952,443~~$72,582,285 as of ~~June~~September 30, 2005 and $64,515,137 as of December 31, 2004.

910

2. Development Costs

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

Three Months Ended
June 30

Six Months Ended
June 30

2005

2004

2005

2004

Cumulative development costs (over) the amount deducted - beginning of period

$
(1,178,666
)
$
(1,197,564
)
$
(319,927
)
$
(1,583,988
)
Actual development costs

(6,972,845
)
(2,482,431
)
(14,631,584
)
(7,196,007
)
Development costs deducted

7,200,000

5,100,000

14,000,000

10,200,000

Cumulative development costs (over) under the amount deducted - end of period

$
(951,511
)
$
1,420,005

$
(951,511
)
$
1,420,005

	Development Costs
	Three Months Ended						Nine Months Ended
	September 30						September 30
	2005			2004			2005			2004
Cumulative actual costs (over) under the amount deducted - beginning of period	$	(951,511	)	$	1,420,005		$	(319,927	)	$	(1,583,988	)
Actual costs	(10,883,949		)	(3,757,300		)	(25,515,533		)	(10,953,307		)
Budgeted costs deducted	9,900,000			5,100,000			23,900,000			15,300,000
Cumulative actual costs (over) under the amount deducted - end of period	$	(1,935,460	)	$	2,762,705		$	(1,935,460	)	$	2,762,705

The monthly development ~~cost~~ deduction was ~~$1.7 million throughout 2004 until it was increased to~~ $2 million ~~beginning with the October 2004 distribution because of~~in January 2005; it has been increased ~~drilling in Oklahoma. Because~~three times during 2005 as a result of increased development activity and higher ~~drilling costs, the monthly development cost deduction was~~costs. The deductions were increased to $2.4 million beginning with the February ~~2005~~ distribution, ~~and was increased again~~ to $3.3 million beginning with the July ~~2005~~distribution and to $5.1 million beginning with the October distribution. XTO Energy Inc. has advised the trustee that it currently expects the monthly ~~development cost~~ deduction will remain at ~~$3.3~~$5.1 million for the remainder of 2005, subject to reevaluation and revision as necessary.

3. Contingencies

Litigation

XTO Energy Inc. 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 Inc.

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 Inc. The plaintiff alleges that XTO Energy Inc. 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 Inc. to cease the allegedly improper measuring practices. This lawsuit against XTO Energy Inc. 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 Inc. 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 occurred in March 2005, and in May 2005, the special master, who was appointed by the district judge to expedite matters and

make recommendations to the district judge in the case, issued a report and recommendation to dismiss the case against some ~~of the~~ defendants but to retain jurisdiction of the case involving XTO Energy Inc. and other defendants. XTO Energy Inc. and other defendants filed a motion to modify the special master’s ~~report.~~report, requesting the district judge to also dismiss the case as to XTO Energy Inc. and other defendants. While XTO Energy Inc. 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 Inc. management’s opinion, is not currently expected to be material to the trust’s annual distributable income, financial position or liquidity.

Certain of the underlying properties are involved in various other lawsuits and certain governmental proceedings arising in the ordinary course of business. XTO Energy Inc. 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 Inc. has advised the trustee that it believes the trust is not subject to these withholding requirements. However, regulations 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.

1112

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 2004 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 ~~June~~September 30, 2005, net profits income was ~~$22,965,660,~~$24,325,921, as compared to ~~$18,289,557~~$23,521,511 for ~~second~~third quarter 2004. This ~~26%~~3% increase in net profits income is primarily the result of higher oil and gas prices. See “Net Profits Income” on the following page.

After adding interest income of ~~$21,859~~$29,600 and deducting administration expense of ~~$155,479,~~$51,321, distributable income for the quarter ended ~~June~~September 30, 2005 was ~~$22,832,040,~~$24,304,200, or ~~$0.570801~~$0.607605 per unit of beneficial interest. Administration expense for the quarter ~~increased 32%~~decreased 50% from the prior year quarter primarily because of the timing of expenditures. For ~~second~~third quarter 2004, distributable income was ~~$18,178,560~~$23,428,840 or ~~$0.454464~~$0.585721 per unit. Distributions to unitholders for the quarter ended ~~June~~September 30, 2005 were:

Record Date

Payment Date

Distribution
per Unit

April 29, 2005

May 13, 2005

$
0.163129

May 31, 2005

June 14, 2005

0.189000

June 30, 2005

July 15, 2005

0.218672

$
0.570801

		Distribution
Record Date	Payment Date	per Unit

July 29, 2005	August 12, 2005	$	0.210129
August 31, 2005	September 15, 2005	0.177270
September 30, 2005	October 17, 2005	0.220206
		$	0.607605

~~Six~~Nine Months

For the ~~six~~nine months ended ~~June~~September 30, 2005, net profits income was ~~$48,784,600,~~$73,110,521, compared with ~~$37,346,788~~$60,868,299 for the same 2004 period. This ~~31%~~20% increase in net profits income is primarily the result of higher oil and gas prices. See “Net Profits Income” on the following page.

After adding interest income of ~~$41,909~~$71,509 and deducting administration expense of ~~$296,309,~~$347,630, distributable income for the ~~six~~nine months ended ~~June~~September 30, 2005 was ~~$48,530,200,~~$72,834,400, or ~~$1.213255~~$1.820860 per unit of beneficial interest. Administration expense for the first ~~six~~nine months of 2005 was ~~46%~~14% higher than in the first ~~six~~nine months of 2004 primarily because of fees related to the ~~2004~~ audit of the trust’s internal control over financial reporting for 2004 and the timing of expenditures. For the ~~six~~nine months ended ~~June~~September 30, 2004, distributable income was ~~$37,155,320,~~$60,584,160 or ~~$0.928883~~$1.514604 per unit.

1213

Net Profits Income

Net profits income is recorded when received by the trust, which is the month following receipt by XTO Energy Inc., 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.

1314

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	Three Months Ended September 30 (a)				Increase	Nine Months Ended September 30 (a)				Increase
	2005		2004		(Decrease)	2005		2004		(Decrease)	2005		2004		(Decrease)	2005		2004		(Decrease)
Sales Volumes
Gas (Mcf) (b)
Underlying properties	7,212,301		7,360,541		(2)%	14,702,133		15,121,407		(3)%	7,639,778		7,610,566		—	22,341,911		22,731,973		(2)%
Average per day	81,037		81,784		(1)%	81,227		83,085		(2)%	83,041		82,724		—	81,839		82,963		(1)%
Net profits interests	3,901,719		3,875,212		1%	8,110,956		8,074,850		—	3,922,803		4,323,048		(9)%	12,033,759		12,397,898		(3)%

Oil (Bbls) (b)
Underlying properties	85,227		79,676		7%	159,640		157,852		1%	85,765		82,513		4%	245,405		240,365		2%
Average per day	958		885		8%	882		867		2%	932		897		4%	899		877		3%
Net profits interests	44,828		43,311		4%	88,951		91,122		(2)%	42,973		47,015		(9)%	131,924		138,137		(4)%

Average Sales Prices
Gas (per Mcf)	$5.85		$4.77		23%	$6.04		$4.68		29%	$6.17		$5.50		12%	$6.09		$4.96		23%
Oil (per Bbl)	$50.38		$35.60		42%	$47.89		$33.58		43%	$52.49		$38.59		36%	$49.49		$35.30		40%

Revenues
Gas sales	$	42,222,430	$	35,146,341	20%	$	88,800,106	$	70,812,923	25%	$	47,155,805	$	41,844,270	13%	$	135,955,911	$	112,657,193	21%
Oil sales	4,293,413		2,836,538		51%	7,644,403		5,300,487		44%	4,501,609		3,183,986		41%	12,146,012		8,484,473		43%

Total Revenues	46,515,843		37,982,879		22%	96,444,509		76,113,410		27%	51,657,414		45,028,256		15%	148,101,923		121,141,666		22%

Costs
Taxes, transportation and other	4,315,085		3,500,087		23%	8,924,224		6,511,021		37%	4,606,027		3,819,435		21%	13,530,251		10,330,456		31%
Production expense	4,387,547		4,690,989		(6)%	8,727,744		9,105,656		(4)%	4,761,078		4,666,777		2%	13,488,822		13,772,433		(2)%
Development costs (c)	7,200,000		5,100,000		41%	14,000,000		10,200,000		37%	9,900,000		5,100,000		94%	23,900,000		15,300,000		56%
Overhead	1,906,136		1,829,857		4%	3,811,791		3,613,248		5%	1,982,908		2,040,155		(3)%	5,794,699		5,653,403		2%

Total Costs	17,808,768		15,120,933		18%	35,463,759		29,429,925		21%	21,250,013		15,626,367		36%	56,713,772		45,056,292		26%

Net Proceeds	28,707,075		22,861,946		26%	60,980,750		46,683,485		31%	30,407,401		29,401,889		3%	91,388,151		76,085,374		20%

Net Profits Percentage	80%		80%			80%		80%			80%		80%			80%		80%

Net Profits Income	$	22,965,660	$	18,289,557	26%	$	48,784,600	$	37,346,788	31%	$	24,325,921	$	23,521,511	3%	$	73,110,521	$	60,868,299	20%

(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~~September 30 generally represent production for the period ~~February~~May through ~~April~~July and (2) oil and gas sales for the ~~six~~nine months ended ~~June~~September 30 generally represent production for the period November through ~~April.~~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 expense 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.

1415

The following are explanations of significant variances on the underlying properties from ~~second~~third quarter 2004 to ~~second~~third quarter 2005 and from the first ~~six~~nine months of 2004 to the comparable period in 2005:

Sales Volumes

Gas

Third quarter gas sales volumes remained relatively unchanged as increased production from new wells and workovers and the timing of cash receipts was offset by natural production decline. Gas sales volumes ~~decreased 2%~~ for the ~~second quarter and 3% for the six-month~~nine-month period decreased 2% primarily because of natural production decline and the timing of cash receipts, partially offset by increased production from new wells and workovers.

Oil

Oil sales volumes increased 7%4% for the ~~second~~third quarter and 1%2% for the ~~six-month~~nine-month period primarily because of increased production from new wells and workovers and the timing of cash receipts, partially offset by natural production decline.

See “Gulf of Mexico Hurricanes” below.

Sales Prices

Gas

The ~~second~~third quarter 2005 average gas price was ~~$5.85~~$6.17 per Mcf, a ~~23%~~12% increase from the ~~second~~third quarter 2004 average gas price of ~~$4.77~~$5.50 per Mcf. For the ~~six-month~~nine-month period, the average gas price increased ~~29%~~23% to ~~$6.04~~$6.09 per Mcf in 2005 from ~~$4.68~~$4.96 per Mcf in 2004. Gas prices increased for the ~~second~~third quarter and for the ~~six-month~~nine-month period primarily because of increased demand, warmer-than-normal temperatures and ~~declining North American production.~~reduced gas production as a result of July tropical storms in the Gulf of Mexico. Prices will continue to be affected by weather, the U.S. economy, the level of North American production, crude oil prices and import levels of liquified natural gas, and are expected to remain volatile. The ~~second~~third quarter 2005 gas price is primarily related to production from ~~February~~May through ~~April~~July 2005, when the average NYMEX price was ~~$6.80~~$7.08 per MMBtu, or ~~22%~~13% higher than the comparable 2004 period average NYMEX price of ~~$5.56~~$6.25 per MMBtu. The average NYMEX price for ~~May~~August and ~~June~~September 2005 was ~~$6.85~~$10.68 per MMBtu. At ~~July 15,~~October 21, 2005, the average NYMEX futures price for the following twelve months was ~~$8.30~~$11.58 per MMBtu. ~~Recent~~The trust gas ~~prices have averaged approximately $0.50~~price for August 2005 production, included in the October 2005 distribution, was $1.05 per ~~MMBtu~~Mcf lower than the NYMEX price. This decrement is expected to widen for September and October production, which will affect the November and December 2005 distributions.

Oil

The ~~second~~third quarter 2005 average oil price was ~~$50.38~~$52.49 per Bbl, a ~~42%~~36% increase from the ~~second~~third quarter 2004 average oil price of ~~$35.60~~$38.59 per Bbl. The year-to-date average oil price increased ~~43%~~40% to ~~$47.89~~$49.49 per Bbl in 2005 from ~~$33.58~~$35.30 per Bbl in 2004. Oil prices increased for the ~~second~~third quarter and for the ~~six-month~~nine-month period primarily because of increasing global demand and supply shortage concerns, inadequate refining capacity, reduced production as a result of July tropical storms in the ~~weaker U.S. dollar,~~Gulf of Mexico, market speculation and political ~~instability.~~instability, and are expected to remain volatile. Oil prices increased to record levels in ~~July~~August 2005, exceeding ~~$61.00~~$69.00 per Bbl. The average NYMEX price for ~~May~~August and ~~June~~September 2005 was ~~$53.18~~$65.22 per Bbl. At ~~July 15,~~October 21, 2005, the average NYMEX futures price for the following twelve months was ~~$59.93~~$61.12 per Bbl. Recent trust oil prices have averaged approximately ~~$2.50~~$2.40 per Bbl lower than the NYMEX price.

1516

See “Gulf of Mexico Hurricanes” below.

Costs

Taxes

Taxes, transportation and other increased ~~23%~~21% for the quarter and ~~37%~~31% for the ~~six-month~~nine-month period primarily because of increased production taxes related to higher revenues. ~~In addition, increased taxes, transportation and other~~The increase for the ~~six-month~~nine-month period was ~~because of increased~~also affected by property taxes related to the timing of cash disbursements.

Production

Production expense ~~decreased 6%~~increased 2% for the quarter and 4%decreased 2% for the ~~six-month period~~nine-month period. Fluctuations in production expense are primarily because of ~~decreased maintenance, insurance and labor costs related to~~ the timing of maintenance ~~projects.~~projects as well as the timing of cash disbursements.

Development

Development costs deducted in the calculation of net profits income are based on the development budget. These development costs increased ~~41%~~94% for the ~~second~~third quarter and ~~37%~~56% for the ~~six-month~~nine-month period primarily because of increased development activity in western Oklahoma and higher drilling costs in 2005. During the first ~~half~~nine months of 2005, 1324 wells were completed and ~~five~~four wells were pending completion on the underlying properties at ~~June~~September 30. XTO Energy Inc. has informed the trustee that it plans to drill ~~up to 29~~37 wells and perform 22approximately 25 workovers and 5065 restimulations during 2005.

As of December 31, 2004, cumulative actual development costs exceeded cumulative ~~development~~budgeted costs deducted by $319,927. In calculating net profits income, XTO Energy Inc. deducted budgeted ~~development~~ costs of ~~$7.2~~$9.9 million for the quarter and ~~$14~~$23.9 million for the ~~six-month~~nine-month period. After considering actual ~~development~~ costs of $7$10.9 million for the quarter and ~~$14.6~~$25.5 million for the ~~six-month~~nine-month period, cumulative actual ~~development~~ costs exceeded cumulative budgeted ~~development~~ costs deducted by ~~approximately $1~~$1.9 million at ~~June~~September 30, 2005. See Note 2 to Condensed Financial Statements.

Because of increased development activity and higher ~~drilling~~ costs, the monthly development cost deduction was increased from $2.4 million to $3.3 million beginning with the July 2005 distribution and to $5.1 million beginning with the October 2005 distribution. Development projects have recently been accelerated because of gas supply disruptions and higher prices. XTO Energy Inc. has advised the trustee that it currently expects the monthly development cost deduction will remain at ~~$3.3~~$5.1 million for the remainder of 2005, subject to reevaluation and revision as necessary.

Overhead

Overhead ~~increased 4%~~decreased 3% for the quarter and 5%increased 2% for the ~~six-month~~nine-month period. Decreased overhead for the quarter is primarily because of the timing of an annual Oklahoma administrative fee. Increased overhead for the nine-month period is primarily because of the annual rate adjustment based on an industry index.

16Gulf of Mexico Hurricanes

In late August and September 2005, hurricanes in the Gulf of Mexico disrupted a significant portion of U.S. oil and gas production, leading to higher prices. These increased prices will affect distributions to unitholders beginning with the November 2005 distribution to be paid in December 2005. The underlying

properties to the trust are not located near the Gulf and related production was not significantly affected. However, because of greater supply and weaker demand in areas where trust related oil and gas is produced, the price received for such production will be significantly lower than the price received for Gulf production or NYMEX prices. As a result of storm damages and related supply shortages, production expense and development costs are expected to increase throughout the industry. The duration of these higher prices and costs cannot be predicted.

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 and expenses, oil and gas prices and differentials to NYMEX prices, supply shortages, future drilling, workover and restimulation plans, distributions to unitholders 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, 2004, which is incorporated by this reference as though fully set forth herein. Although XTO Energy Inc. and the trustee believe that the expectations reflected in such forward-looking statements are reasonable, neither XTO Energy Inc. 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, 2004.

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 Inc. 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.

1718

PART II - OTHER INFORMATION

Items 1 through 5.

Not applicable.

Item 6. Exhibits.

(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 14, 2005 (incorporated herein by reference)

1819

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: ~~July 20,~~October 25, 2005	By	/S/ LOUIS G. BALDWIN
		Louis G. Baldwin
		Executive Vice President
		and Chief Financial Officer

1920

	Three Months Ended June 30				Six Months Ended June 30
	2005		2004		2005		2004

Net profits income	$	22,965,660	$	18,289,557	$	48,784,600	$	37,346,788

Interest income	21,859		6,751		41,909		10,853

Total income	22,987,519		18,296,308		48,826,509		37,357,641

Administration expense	155,479		117,748		296,309		202,321

Distributable income	$	22,832,040	$	18,178,560	$	48,530,200	$	37,155,320

Distributable income per unit (40,000,000 units)	$	0.570801	$	0.454464	$	1.213255	$	0.928883

Record Date	Payment Date	Distribution per Unit

April 29, 2005	May 13, 2005	$	0.163129
May 31, 2005	June 14, 2005	0.189000
June 30, 2005	July 15, 2005	0.218672
		$	0.570801