UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

x~~QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934~~ ~~For the quarterly period ended March 31, 2007~~ OR o		QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2007

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		(I.R.S. Employer
incorporation or organization)		Identification No.)

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

(877) 228-5083

(Registrant’s telephone number, including area code)

NONE

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer x Accelerated filer o Non-accelerated filer 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 x

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

Outstanding as of ~~April~~October 1, 2007

40,000,000

HUGOTON ROYALTY TRUST

FORM 10-Q FOR THE QUARTERLY PERIOD ENDED ~~MARCH 31,~~SEPTEMBER 30, 2007

TABLE OF CONTENTS

~~TABLE OF CONTENTS~~



		Glossary of Terms

PART I.		FINANCIAL INFORMATION

~~Item 1.~~		~~Financial Statements~~

Item 1.	Financial Statements

	Report of Independent Registered Public Accounting Firm

		Condensed Statements of Assets, Liabilities and Trust Corpus at ~~March 31,~~September 30, 2007 and December 31, 2006

		Condensed Statements of Distributable Income for the Three and Nine Months Ended ~~March 31,~~September 30, 2007 and 2006

		Condensed Statements of Changes in Trust Corpus for the Three and Nine Months Ended ~~March 31,~~September 30, 2007 and 2006

		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 1A.		Risk Factors

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

net profits income		Net proceeds multiplied by the net profits percentage of 80%, which is paid to the trust by XTO Energy. “Net profits income” is referred to as “royalty income” for tax reporting purposes.

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

		80% net profits interests- interests that entitle the trust to receive 80% of the net proceeds from the underlying properties.

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 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 ~~March 31,~~September 30, 2007 and the distributable income and changes in trust corpus for the ~~three-month~~three- and nine-month periods ended ~~March 31,~~September 30, 2007 and 2006 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 ~~March 31,~~September 30, 2007 and the related condensed statements of distributable income and changes in trust corpus for the ~~three-month~~three- and nine-month periods ended ~~March 31,~~September 30, 2007 and 2006. 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, 2006, 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 2006 Annual Report on Form 10-K, and in our report dated February 28, 2007, 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, 2006 is fairly stated, in all material respects, in relation to the statement of assets, liabilities and trust corpus included in the trust’s 2006 Annual Report on Form 10-K from which it has been derived.

KPMG LLP

Dallas, Texas

~~April 26,~~October 18, 2007

HUGOTON ROYALTY TRUST

Condensed Statements of Assets, Liabilities and Trust Corpus

March 31,

December 31,

2007

2006

(Unaudited)

ASSETS

Cash and short-term investments

$
3,718,760

$
1,813,000

Net profits interests in oil and gas properties - net (Note 1)

161,914,911

163,796,772

$
165,633,671

$
165,609,772

LIABILITIES AND TRUST CORPUS

Distribution payable to unitholders

$
3,718,760

$
1,813,000

Trust corpus (40,000,000 units of beneficial interest authorized and outstanding)

161,914,911

163,796,772

$
165,633,671

$
165,609,772

~~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 March 31

2007

2006

Net profits income

$
16,735,385

$
39,085,894

Interest income

29,047

86,245

Total income

16,764,432

39,172,139

Administration expense

522,152

130,539

Distributable income

$
16,242,280

$
39,041,600

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

$
0.406057

$
0.976040

~~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 March 31

2007

2006

Trust corpus, beginning of period

$
163,796,772

$
171,935,330

Amortization of net profits interests

(1,881,861
)
(2,738,242
)

Distributable income

16,242,280

39,041,600

Distributions declared

(16,242,280
)
(39,041,600
)

Trust corpus, end of period

$
161,914,911

$
169,197,088

	September 30,	December 31,
	2007	2006
	(Unaudited)

ASSETS

Cash and short-term investments	$5,384,480	$1,813,000

Net profits interests in oil and gas properties - net (Note 1)	157,533,675	163,796,772

	$162,918,155	$165,609,772

LIABILITIES AND TRUST CORPUS

Distribution payable to unitholders	$5,384,480	$1,813,000

Trust corpus (40,000,000 units of beneficial interest authorized and outstanding)	157,533,675	163,796,772

	$162,918,155	$165,609,772

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		Nine Months Ended
	September 30		September 30
	2007	2006	2007	2006

Net profits income	$17,870,756	$16,962,944	$55,857,387	$77,173,910

Interest income	38,226	25,551	107,395	161,893

Total income	17,908,982	16,988,495	55,964,782	77,335,803

Administration expense	174,302	67,695	1,141,822	401,163

Distributable income	$17,734,680	$16,920,800	$54,822,960	$76,934,640

Distributable income per unit (40,000,000 units)	$0.443367	$0.423020	$1.370574	$1.923366

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
	2007		2006		2007		2006

Trust corpus, beginning of period	$159,594,894		$167,104,635		$163,796,772		$171,935,330

Amortization of net profits interests	(2,061,219	)	(1,798,615	)	(6,263,097	)	(6,629,310	)

Distributable income	17,734,680		16,920,800		54,822,960		76,934,640

Distributions declared	(17,734,680	)	(16,920,800	)	(54,822,960	)	(76,934,640	)

Trust corpus, end of period	$157,533,675		$165,306,020		$157,533,675		$165,306,020

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 U.S. generally accepted accounting principles (“U.S. 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 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 U.S. 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 U.S. GAAP. This comprehensive basis of accounting other than U.S. 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 U.S. 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 ~~$85,152,040~~$89,533,276 as of ~~March 31,~~September 30, 2007 and $83,270,179 as of December 31, 2006.

2. Development Costs

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

Three Months Ended
March 31

2007

2006

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

$
(3,410,174
)
$
113,905

Actual costs

(3,778,138
)
(12,450,558
)
Budgeted costs deducted

12,500,000

9,900,000

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

$
5,311,688

$
(2,436,653
)

	Three Months Ended				Nine Months Ended
	September 30				September 30
	2007		2006		2007		2006

Cumulative actual costs under (over) the amount deducted - beginning of period	$3,050,773		$(896,032	)	$(3,410,174	)	$113,905
Actual costs	(11,843,853	)	(18,622,306	)	(25,632,906	)	(42,132,243	)
Budgeted costs deducted	11,250,000		14,200,000		31,500,000		36,700,000
Cumulative actual costs under (over) the amount deducted - end of period	$2,456,920		$(5,318,338	)	$2,456,920		$(5,318,338	)

As a result of increased development activity and higher costs, the monthly development deduction was increased to $5.0 million beginning with the August 2006 distribution. With a reduction in development activity in first quarter 2007 and based on the development budget for 2007, the development cost deduction was lowered to $3.75 million beginning with the February 2007 distribution. Because of lower than anticipated actual costs as a result of the timing of expenditures, the development cost deduction was lowered to $2.0 million for the April ~~2007 distribution. The development cost deduction is expected to be maintained at $2.0 million for the~~and May 2007 ~~distribution,~~distributions, but ~~is expected to be~~was increased to $3.75 million with the June 2007 distribution and is expected to be maintained at that level through year end.

XTO Energy has advised the trustee that total 2007 budgeted development costs for the underlying properties are approximately $46.0 million. The 2007 budget year generally coincides with the trust distribution months from April 2007 through March 2008. The monthly development cost deduction will be reevaluated by XTO Energy and revised as necessary, based on the 2007 budget and the timing and amount of actual expenditures.

3. Contingencies

Litigation

On October 17, 1997, an action, styled United States of America ex rel. Grynberg v. Cross Timbers Oil Company, et alal.., 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, attorney’s 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. In response to a motion to dismiss filed by XTO Energy and other defendants, in October 2006 the district

judge held that Grynberg failed to establish the jurisdictional requirements to maintain the action against

XTO Energy and other defendants and dismissed the actions for lack of subject matter jurisdiction. Grynberg has filed an appeal of this decision. While XTO Energy is unable to predict the final 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.

An amended petition for a class action lawsuit, Beer, et al. v. XTO Energy Inc., was filed in January 2006, in the District Court of Texas County, Oklahoma by royalty owners of natural gas wells in Oklahoma. The plaintiffs allege that XTO Energy has not properly accounted to the plaintiffs for the royalties to which they are entitled and seek an accounting regarding the natural gas and other products produced from their wells and the prices paid for the natural gas and other products produced, and for payment of the monies allegedly owed since June 2002, with a certain limited number of plaintiffs claiming monies owed for additional time. A hearing on the class certification has not been scheduled. The plaintiffs have not ~~stated~~alleged in their petition an amount that they are seeking. XTO Energy has informed the trustee that it believes that it has strong defenses to this lawsuit and intends to vigorously defend its position. However, if XTO Energy ultimately makes any settlement payments or receives a judgment against it, the trust will bear its 80% share of such settlement or judgment related to production from the underlying properties. 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. XTO Energy has informed the trustee that, although the amount of any reduction in net proceeds is not presently determinable, in its management’s opinion, the amount 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 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 could be issued by the various states which could change this conclusion. Should the trust be 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 2006 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 ~~March 31,~~September 30, 2007, net profits income was ~~$16,735,385,~~$17,870,756, as compared to ~~$39,085,894~~$16,962,944 for ~~first~~third quarter 2006. ~~Decreased~~This 5% increase in net profits income is primarily the result of lower development costs and higher natural gas ~~prices.~~prices, partially offset by lower oil prices and lower oil and gas sales volumes. See “Net Profits Income” ~~below.~~on the following page.

After adding interest income of ~~$29,047~~$38,226 and deducting administration expense of ~~$522,152,~~$174,302, distributable income for the quarter ended ~~March 31,~~September 30, 2007 was ~~$16,242,280,~~$17,734,680, or ~~$0.406057~~$0.443367 per unit of beneficial interest. Administration expense for the quarter increased from the prior year quarter primarily because of higher costs related to additional unitholder tax reporting, an increased number of unitholders and the timing of expenditures. ~~Decreased interest income over these periods was because of decreased net profits income, partially offset by higher interest rates.~~ For ~~first~~third quarter 2006, distributable income was ~~$39,041,600,~~$16,920,800 or ~~$0.976040~~$0.423020 per unit. Distributions to unitholders for the quarter ended ~~March 31,~~September 30, 2007 were:

Distribution

Record Date

Payment Date

per Unit

January 31, 2007

February 14, 2007

$
0.144052

February 28, 2007

March 14, 2007

0.169036

March 30, 2007

April 16, 2007

0.092969

$
0.406057

		Distribution
Record Date	Payment Date	per Unit

July 31, 2007	August 14, 2007	$0.165850
August 31, 2007	September 17, 2007	0.142905
September 28, 2007	October 15, 2007	0.134612
		$0.443367

Nine Months

For the nine months ended September 30, 2007, net profits income was $55,857,387, compared with $77,173,910 for the same 2006 period. This 28% decrease in net profits income is primarily the result of lower gas prices and gas and oil sales volumes, partially offset by lower development costs. See “Net Profits Income” on the following page.

After adding interest income of $107,395 and deducting administration expense of $1,141,822, distributable income for the nine months ended September 30, 2007 was $54,822,960, or $1.370574 per unit of beneficial interest. Administration expense for the first nine months of 2007 was significantly higher than in the first nine months of 2006 primarily because of higher costs related to additional unitholder tax reporting, an increased number of unitholders and the timing of expenditures. Decreased interest income over these periods was primarily because of lower net profits income. For the nine months ended September 30, 2006, distributable income was $76,934,640, or $1.923366 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 March 31 (a)

Increase

2007

2006

(Decrease)

Sales Volumes

Gas (Mcf) (b)

Underlying properties

7,086,751

7,410,013

(4%)

Average per day

77,030

80,544

(4%)

Net profits interests

2,649,964

4,330,569

(39%)

Oil (Bbls) (b)

Underlying properties

68,126

78,265

(13%)

Average per day

741

851

(13%)

Net profits interests

33,177

47,049

(29%)

Average Sales Prices

Gas (per Mcf)

$     5.94

$     9.10

(35%)

Oil (per Bbl)

$   57.17

$   59.10

(3%)

Revenues

Gas sales

$
42,065,337

$
67,404,751

(38%)

Oil sales

3,894,698

4,625,299

(16%)

Total Revenues

45,960,035

72,030,050

(36%)

Costs

Taxes, transportation and other

4,864,798

5,727,555

(15%)

Production expense

5,458,567

5,546,717

(2%)

Development costs (c)

12,500,000

9,900,000

26%

Overhead

2,217,439

1,998,411

11%

Total Costs

25,040,804

23,172,683

8%

Net Proceeds

20,919,231

48,857,367

(57%)

Net Profits Percentage

80%

80%

Net Profits Income

$
16,735,385

$
39,085,894

(57%)

	Three Months			Nine Months
	Ended September 30 (a)		Increase	Ended September 30 (a)		Increase
	2007	2006	(Decrease)	2007	2006	(Decrease)
Sales Volumes
Gas (Mcf) (b)
Underlying properties	6,980,106	7,476,512	(7%)	20,838,899	22,062,828	(6%)
Average per day	75,871	81,266	(7%)	76,333	80,816	(6%)
Net profits interests	2,903,001	2,844,750	2%	8,820,209	10,484,633	(16%)

Oil (Bbls) (b)
Underlying properties	76,832	82,327	(7%)	223,555	243,311	(8%)
Average per day	835	895	(7%)	819	891	(8%)
Net profits interests	33,044	32,641	1%	106,310	116,544	(9%)

Average Sales Prices
Gas (per Mcf)	$5.93	$5.67	5%	$6.02	$7.03	(14%)
Oil (per Bbl)	$65.14	$70.13	(7%)	$60.41	$64.34	(6%)

Revenues
Gas sales	$41,401,782	$42,374,707	(2%)	$125,515,708	$155,169,433	(19%)
Oil sales	5,005,105	5,773,777	(13%)	13,505,539	15,654,780	(14%)

Total Revenues	46,406,887	48,148,484	(4%)	139,021,247	170,824,213	(19%)

Costs
Taxes, transportation and other	4,642,514	4,639,339	-	14,096,130	15,235,567	(7%)
Production expense	5,860,762	5,974,007	(2%)	16,876,291	16,299,260	4%
Development costs (c)	11,250,000	14,200,000	(21%)	31,500,000	36,700,000	(14%)
Overhead	2,315,166	2,131,458	9%	6,727,092	6,121,999	10%

Total Costs	24,068,442	26,944,804	(11%)	69,199,513	74,356,826	(7%)

Net Proceeds	22,338,445	21,203,680	5%	69,821,734	96,467,387	(28%)

Net Profits Percentage	80%	80%		80%	80%

Net Profits Income	$17,870,756	$16,962,944	5%	$55,857,387	$77,173,910	(28%)

~~(a)~~	(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 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. 14	Because of the two-month interval between time of production and receipt of net profits income by the trust, oil and gas sales for the quarter ended March 31 generally represent production for the period November through January.

~~(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.~~

The following are explanations of significant variances on the underlying properties from ~~first~~third quarter 2007 to third quarter 2006 and from the first nine months of 2007 to ~~first quarter 2007:~~the comparable period in 2006:

Sales Volumes

Gas

Gas sales volumes decreased 4%7% for the third quarter and ~~oil sales volumes decreased 13% from first quarter 2006 to first quarter 2007. Lower gas sales volumes are~~6% for the nine-month period primarily because of ~~weather-related production problems in Oklahoma in first quarter 2007 and~~ natural production decline, partially offset by increased production from new wells and workovers and the timing of cash receipts. ~~Decreased oil~~

Oil

Oil sales volumes ~~are~~decreased 7% for the third quarter and 8% for the nine-month period primarily because of natural production decline, ~~and prior period volume adjustments in 2007,~~ partially offset by increased production from new wells and workovers and the timing of cash receipts. In addition, oil sales volumes increased for the third quarter and decreased for the nine-month period because of the effects of prior period volume adjustments.

Sales Prices

Gas

The ~~first~~third quarter 2007 average gas price was ~~$5.94~~$5.93 per Mcf, a ~~35% decrease~~5% increase from the ~~first~~third quarter 2006 average gas price of ~~$9.10~~$5.67 per Mcf. ~~Gas prices~~For the nine-month period, the average gas price decreased ~~primarily due~~14% to ~~the effect~~$6.02 per Mcf in 2007 from $7.03 per Mcf in 2006. The aftermath of 2005 Gulf of Mexico ~~hurricanes on first quarter 2006 gas prices, versus the absence of 2006 Gulf of Mexico~~ hurricane activity ~~affecting first quarter 2007 gas prices. Much colder temperatures during February 2007 caused~~elevated 2006 prices, while the lack of such activity in 2006 contributed to ~~increase.~~lower prices in 2007. 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. Natural~~ gas, ~~prices~~and are expected to remain volatile. The third quarter 2007 gas price is primarily related to production from May through July 2007, when the average NYMEX price was $7.34 per MMBtu, or 16% higher than the comparable 2006 period average NYMEX price of $6.34 per MMBtu. The average NYMEX price for ~~February~~August and ~~March~~September 2007 was ~~$7.23~~$5.77 per MMBtu. At ~~April 18,~~October 15, 2007, the average NYMEX futures price for the following twelve months was ~~$8.49~~$7.99 per MMBtu. Recent trust gas prices have averaged approximately 8%20% lower than the NYMEX price.

Recent gas prices in the Rocky Mountain region have been significantly lower as a result of pipeline constraints and lower regional demand. This has resulted in lower realized prices for the trust’s Wyoming gas production. Realized gas prices for August 2007 Wyoming production were approximately 41% lower than the NYMEX price. With current pipeline expansions not projected for completion until early 2008, the lower realized gas prices are expected to continue for the remainder of the year. At October 15, 2007, the average futures price for the following three months is expected to be approximately 38% lower than the NYMEX price. Wyoming gas production was approximately 28% of total trust gas production for the nine-month period ended September 30, 2007.

Oil

The ~~first~~third quarter 2007 average oil price was ~~$57.17~~$65.14 per Bbl, a 3%7% decrease from the ~~first~~third quarter 2006 average oil price of ~~$59.10~~$70.13 per Bbl. The year-to-date average oil price decreased 6% to $60.41 per Bbl in 2007 from $64.34 per Bbl in 2006. Oil prices ~~decreased from first quarter 2006 to first quarter 2007~~were lower for both periods primarily because of ~~warmer-than-normal temperatures~~higher oil prices in ~~January 2007. With~~2006 as a result of 2005 Gulf of Mexico hurricanes, supply shortage concerns and inadequate sour

crude refining capacity. Oil prices during the ~~onset of colder temperatures in February~~third quarter fluctuated between approximately $69.00 and $84.00 per Bbl. In October 2007, ~~and because of~~ rising tension in the Middle East, ~~recent~~weakness in the dollar and strong demand caused oil prices ~~have fluctuated between $60.00 and $66.00~~to increase to record levels of $90.00 per Bbl. Oil prices are expected to remain volatile. The average NYMEX price for ~~February~~August and ~~March~~September 2007 was ~~$60.15~~$75.75 per Bbl. At ~~April 18,~~October 15, 2007, the average NYMEX futures price for the following twelve months was ~~$67.19~~$82.16 per Bbl. Recent trust oil prices have averaged approximately 5%4% lower than the NYMEX price.

Costs

Taxes, Transportation and Other

Taxes, transportation and other ~~decreased 15%~~were relatively unchanged for the ~~first~~ quarter and decreased 7% for the nine-month period primarily because of decreased production taxes related to lower revenues, partially offset by increased property taxes related to 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 decreased 21% for ~~first~~the third quarter ~~2007 increased 26% from~~and 14% for the ~~prior year quarter~~nine-month period primarily because of the timing of development ~~activity.~~activity and expenditures and lower costs. During the first ~~three~~nine months of 2007, ~~four~~24 wells were completed and three wells were pending completion on the underlying properties ~~and seven wells were pending completion~~ at ~~March 31.~~September 30.

As of December 31, 2006, cumulative actual costs exceeded cumulative budgeted costs deducted by approximately $3.4 million. In calculating net profits income, ~~for the quarter ended March 31, 2007,~~ XTO Energy deducted budgeted development costs of ~~$12.5 million.~~$11.3 million for the quarter and $31.5 million for the nine-month period. After considering actual development costs of ~~$3.8~~$11.8 million for the quarter and $25.6 million for the nine-month period, cumulative budgeted costs deducted exceeded actual costs by $5.3 million. First quarter actual development costs primarily relate to disbursements for development activity in fourth quarter 2006. With a reduction in development activity in first quarter 2007 and based on the development budget for 2007, the development cost deduction was lowered to $3.75approximately $2.5 million beginning with the February 2007 distribution. Because of lower than anticipated actual costs as a result of the timing of expenditures, the development cost deduction was lowered to $2.0 million for the April 2007 distribution. The development cost deduction is expected to be maintained at ~~$2.0 million for the May 2007 distribution, but is expected to be increased to $3.75 million with the June 2007 distribution and maintained at that level through year end.~~September 30, 2007.

Overhead

Overhead increased ~~11%~~9% for the quarter and 10% for the nine-month period primarily because of an increased well count and the annual rate adjustment based on an industry ~~index and~~index. In addition, overhead increased for the nine-month period because of the effects of prior period adjustments.

Other

Trustee Brand Change

On October 15, 2007, the Bank of America private wealth management group officially became known as “U.S. Trust, Bank of America Private Wealth Management” as a result of Bank of America’s acquisition of U.S. Trust Corporation. This change is a brand name change only and the legal entity that serves as the trustee for the trust will continue to be Bank of America, N. A.

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, annual and monthly development, production and other costs and expenses, oil and gas prices and differentials to NYMEX prices, supply shortages, future drilling, completion of pipeline expansions, 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 I, Item 1A of the trust’s Annual Report on Form 10-K for the year ended December 31, 2006, 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, 2006.

Item 44. 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~~functioning effectively to ~~material~~ensure that information ~~relating to the trust~~ required to be ~~included~~disclosed in ~~the trust’s periodic filings~~reports filed with the Securities and Exchange ~~Commission.~~Commission is recorded, processed, summarized and reported within the periods required and that this information is accumulated and communicated to allow timely decisions regarding required disclosures. 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.

Not applicable.

Item 1A. Risk Factors.

There have been no material changes in the risk factors disclosed under Part I, Item 1A of the trust’s Annual Report on Form 10-K for the year ended December 31, 2006.

Items 2 through 5.

Not applicable.

Item 6.Exhibits.

(a) Exhibits.

~~Exhibit Number~~	Exhibit Number
~~and Description~~	and Description

~~(15)~~	(15)	Awareness letter of KPMG LLP

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

~~(32)~~	(32)	Section 1350 Certification

~~(99)~~	(99)	Items 1A, 7 and 7A to the Annual Report on Form 10-K for Hugoton Royalty Trust filed with the Securities and Exchange Commission on March 1, 2007 (incorporated herein by reference)

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.~~


	XTO ENERGY INC.


Date: ~~April 30,~~October 19, 2007	By	/S/ LOUIS G. BALDWIN
		Louis G. Baldwin
		Executive Vice President
		and Chief Financial Officer

1819

	March 31,		December 31,
	2007		2006
	(Unaudited)
ASSETS

Cash and short-term investments	$	3,718,760	$	1,813,000

Net profits interests in oil and gas properties - net (Note 1)	161,914,911		163,796,772
	$	165,633,671	$	165,609,772

LIABILITIES AND TRUST CORPUS

Distribution payable to unitholders	$	3,718,760	$	1,813,000

Trust corpus (40,000,000 units of beneficial interest authorized and outstanding)	161,914,911		163,796,772
	$	165,633,671	$	165,609,772

	Three Months Ended March 31
	2007		2006

Net profits income	$	16,735,385	$	39,085,894

Interest income	29,047		86,245

Total income	16,764,432		39,172,139

Administration expense	522,152		130,539

Distributable income	$	16,242,280	$	39,041,600

Distributable income per unit (40,000,000 units)	$	0.406057	$	0.976040

	Three Months Ended March 31
	2007			2006
Cumulative actual costs (over) under the amount deducted - beginning of period	$	(3,410,174	)	$	113,905
Actual costs	(3,778,138		)	(12,450,558		)
Budgeted costs deducted	12,500,000			9,900,000
Cumulative actual costs (over) under the amount deducted - end of period	$	5,311,688		$	(2,436,653	)

	Three Months
	Ended March 31 (a)				Increase
	2007		2006		(Decrease)
Sales Volumes
Gas (Mcf) (b)
Underlying properties	7,086,751		7,410,013		(4%)
Average per day	77,030		80,544		(4%)
Net profits interests	2,649,964		4,330,569		(39%)

Oil (Bbls) (b)
Underlying properties	68,126		78,265		(13%)
Average per day	741		851		(13%)
Net profits interests	33,177		47,049		(29%)

Average Sales Prices
Gas (per Mcf)	$ 5.94		$ 9.10		(35%)
Oil (per Bbl)	$ 57.17		$ 59.10		(3%)

Revenues
Gas sales	$	42,065,337	$	67,404,751	(38%)
Oil sales	3,894,698		4,625,299		(16%)
Total Revenues	45,960,035		72,030,050		(36%)

Costs
Taxes, transportation and other	4,864,798		5,727,555		(15%)
Production expense	5,458,567		5,546,717		(2%)
Development costs (c)	12,500,000		9,900,000		26%
Overhead	2,217,439		1,998,411		11%
Total Costs	25,040,804		23,172,683		8%

Net Proceeds	20,919,231		48,857,367		(57%)

Net Profits Percentage	80%		80%

Net Profits Income	$	16,735,385	$	39,085,894	(57%)