Hugoton Royalty Trust (HGTXU) 10-Q 2006 Q2 Quarterly report

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 June 30, 2006

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 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 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 o   Accelerated filer x   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 July 1, 2006

40,000,000

HUGOTON ROYALTY TRUST

FORM 10-Q FOR THE QUARTERLY PERIOD ENDED JUNE 30, 2006

TABLE OF CONTENTS

		Page
	Glossary of Terms		3
PART I.	FINANCIAL INFORMATION
Item 1.	Financial Statements		4
	Report of Independent Registered Public Accounting Firm		5
	Condensed Statements of Assets, Liabilities and Trust Corpus at June 30, 2006 and December 31, 2005		6
	Condensed Statements of Distributable Income for the Three and Six Months Ended June 30, 2006 and 2005		7
	Condensed Statements of Changes in Trust Corpus for the Three and Six Months Ended June 30, 2006 and 2005		8
	Notes to Condensed Financial Statements		9
Item 2.	Trustee’s Discussion and Analysis		12
Item 3.	Quantitative and Qualitative Disclosures about Market Risk		17
Item 4.	Controls and Procedures		17
PART II.	OTHER INFORMATION
Item 1A.	Risk Factors		18
Item 6.	Exhibits		18
	Signatures		19

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HUGOTON ROYALTY TRUST

GLOSSARY OF TERMS

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

Bbl	Barrel (of oil)
Mcf	Thousand cubic feet (of natural gas)
MMBtu	One million British Thermal Units, a common energy measurement
net proceeds	Gross proceeds received by XTO Energy from sale of production from the underlying properties, less applicable costs, as defined in the net profits interest conveyances
net profits income	Net proceeds multiplied by the net profits percentage of 80%, which is 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 expense and development costs

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HUGOTON ROYALTY TRUST

PART I - FINANCIAL INFORMATION

Item 1.  Financial Statements.

The condensed financial statements included herein are presented, without audit, pursuant to the rules and regulations of the Securities and Exchange Commission.  Certain information and footnote disclosures normally included in annual financial statements have been condensed or omitted pursuant to such rules and regulations, although the trustee believes that the disclosures are adequate to make the information presented not misleading.  These condensed financial statements should be read in conjunction with the trust’s financial statements and the notes thereto included in the trust’s Annual Report on Form 10-K.  In the opinion of the trustee, all adjustments, consisting only of normal recurring adjustments, necessary to present fairly the assets, liabilities and trust corpus of the Hugoton Royalty Trust at June 30, 2006 and the distributable income and changes in trust corpus for the three- and six-month periods ended June 30, 2006 and 2005 have been included.  Distributable income for such interim periods is not necessarily indicative of the distributable income for the full year.

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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 30, 2006 and the related condensed statements of distributable income and changes in trust corpus for the three- and six-month periods ended June 30, 2006 and 2005.  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, 2005, 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 2005 Annual Report on Form 10-K, and in our report dated March 16, 2006, 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, 2005 is fairly stated, in all material respects, in relation to the statement of assets, liabilities and trust corpus included in the trust’s 2005 Annual Report on Form 10-K from which it has been derived.

KPMG LLP

Dallas, Texas
July 27, 2006

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HUGOTON ROYALTY TRUST

Condensed Statements of Assets, Liabilities and Trust Corpus

	June 30,		December 31,
	2006		2005
	(Unaudited)
ASSETS
Cash and short-term investments	$	6,923,800	$	13,524,280
Net profits interests in oil and gas properties - net (Note 1)	167,104,635		171,935,330
	$	174,028,435	$	185,459,610
LIABILITIES AND TRUST CORPUS
Distribution payable to unitholders	$	6,923,800	$	13,524,280
Trust corpus (40,000,000 units of beneficial interest authorized and outstanding)	167,104,635		171,935,330
	$	174,028,435	$	185,459,610

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

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HUGOTON ROYALTY TRUST

Condensed Statements of Distributable Income (Unaudited)

	Three Months Ended				Six Months Ended
	June 30				June 30
	2006		2005		2006		2005
Net profits income	$	21,125,072	$	22,965,660	$	60,210,966	$	48,784,600
Interest income	50,097		21,859		136,342		41,909
Total income	21,175,169		22,987,519		60,347,308		48,826,509
Administration expense	202,929		155,479		333,468		296,309
Distributable income	$	20,972,240	$	22,832,040	$	60,013,840	$	48,530,200
Distributable income per unit (40,000,000 units)	$	0.524306	$	0.570801	$	1.500346	$	1.213255

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

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HUGOTON ROYALTY TRUST

Condensed Statements of Changes in Trust Corpus (Unaudited)

	Three Months Ended						Six Months Ended
	June 30						June 30
	2006			2005			2006			2005
Trust corpus, beginning of period	$	169,197,088		$	179,730,111		$	171,935,330		$	182,551,814
Amortization of net profits interests	(2,092,453		)	(2,615,603		)	(4,830,695		)	(5,437,306		)
Distributable income	20,972,240			22,832,040			60,013,840			48,530,200
Distributions declared	(20,972,240		)	(22,832,040		)	(60,013,840		)	(48,530,200		)
Trust corpus, end of period	$	167,104,635		$	177,114,508		$	167,104,635		$	177,114,508

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

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HUGOTON ROYALTY TRUST

Notes to Condensed Financial Statements (Unaudited)

1.   Basis of Accounting

The financial statements of Hugoton Royalty Trust are prepared on the following basis and are not intended to present financial position and results of operations in conformity with generally accepted accounting principles (“GAAP”):

—Net profits income recorded for a month is the amount computed and paid by 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 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 $79,962,316 as of June 30, 2006 and $75,131,621 as of December 31, 2005.

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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						Six Months Ended
	June 30						June 30
	2006			2005			2006			2005
Cumulative actual costs (over) under the amount deducted - beginning of period	$	(2,436,653	)	$	(1,178,666	)	$	113,905		$	(319,927	)
Actual costs	(11,059,379		)	(6,972,845		)	(23,509,937		)	(14,631,584		)
Budgeted costs deducted	12,600,000			7,200,000			22,500,000			14,000,000
Cumulative actual costs (over) the amount deducted - end of period	$	(896,032	)	$	(951,511	)	$	(896,032	)	$	(951,511	)

The monthly development cost deduction was $2 million in January 2005, but was increased three times during 2005 as a result of increased development activity and higher costs.  The deductions were increased to $2.4 million beginning with the February 2005 distribution, to $3.3 million beginning with the July 2005 distribution and to $5.1 million beginning with the October 2005 distribution.  The development cost deduction was lowered to $3.3 million beginning with the January 2006 distribution, but was increased to $4.2 million beginning with the April 2006 distribution.  Based on the current level of development activity and continued increasing costs, XTO Energy has advised the trustee that it will increase the monthly development cost deduction to $5 million beginning with the August 2006 distribution.

XTO Energy has advised the trustee that it has increased the 2006 budget from $40 million to $54 million because of escalated drilling activity and higher costs.  The 2006 budget year generally coincides with the trust distribution months from April 2006 through March 2007.  The monthly development cost deduction will continue to be reevaluated and revised as necessary, based on the 2006 budget and the timing and amount of actual expenditures.

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, 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

10

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 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 and other defendants.  XTO Energy and other defendants filed motions to modify the special master’s report,  requesting the district judge to also dismiss the case as to XTO Energy and other defendants.  The district judge heard oral arguments on December 9, 2005, as to all motions seeking adoption, modification or reversal of the special master’s report, and XTO Energy is awaiting the decision of the district court.  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 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 are subject to change 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.

4.   XTO Energy Inc.

As of May 12, 2006, XTO Energy is no longer a unitholder of the trust, when it distributed all of the 21.7 million trust units it owned to its common stockholders of record on April 26, 2006.  XTO Energy announced in January 2006 that it will consider selling the underlying properties.  Any sale is dependent upon XTO Energy’s ability to structure a tax-efficient transaction and receive sufficient consideration from a buyer it deems to be qualified.

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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 2005 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 30, 2006, net profits income was $21,125,072, as compared to $22,965,660 for second quarter 2005.  This 8% decrease in net profits income is primarily the result of higher development costs, partially offset by higher oil and gas prices.  See “Net Profits Income” on the following page.

After adding interest income of $50,097 and deducting administration expense of $202,929, distributable income for the quarter ended June 30, 2006 was $20,972,240, or $0.524306 per unit of beneficial interest.  Administration expense for the quarter increased 31% from the prior year quarter primarily because of the timing of expenditures and increased unitholder reporting costs.  Increased interest income over these periods was primarily because of higher interest rates.  For second quarter 2005, distributable income was $22,832,040 or $0.570801 per unit.  Distributions to unitholders for the quarter ended June 30, 2006 were:

		Distribution
Record Date	Payment Date	per Unit
April 28, 2006	May 12, 2006	$	0.177224
May 31, 2006	June 14, 2006	0.173987
June 30, 2006	July 17, 2006	0.173095
		$	0.524306

Six Months

For the six months ended June 30, 2006, net profits income was $60,210,966, compared with $48,784,600 for the same 2005 period.  This 23% increase in net profits income is primarily the result of higher oil and gas prices, partially offset by higher development costs.  See “Net Profits Income” on the following page.

After adding interest income of $136,342 and deducting administration expense of $333,468, distributable income for the six months ended June 30, 2006 was $60,013,840, or $1.500346 per unit of beneficial interest.  Administration expense for the first six months of 2006 was 13% higher than in the first six months of 2005 primarily because of increased unitholder reporting costs, partially offset by the timing of expenditures.  Increased interest income over these periods was primarily because of the increase in net profits income and higher interest rates.  For the six months ended June 30, 2005, distributable income was $48,530,200, or $1.213255 per unit.

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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.

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

	Three Months							Six Months
	Ended June 30 (a)						Increase	Ended June 30 (a)						Increase
	2006			2005			(Decrease)	2006			2005			(Decrease)
Sales Volumes
Gas (Mcf)(b)
Underlying properties	7,176,303			7,212,301			—	14,586,316			14,702,133			(1)%
Average per day	80,633			81,037			—	80,587			81,227			(1)%
Net profits interests	3,309,314			3,901,719			(15)%	7,639,883			8,110,956			(6)%
Oil (Bbls)(b)
Underlying properties	82,719			85,227			(3)%	160,984			159,640			1%
Average per day	929			958			(3)%	889			882			1%
Net profits interests	36,854			44,828			(18)%	83,903			88,951			(6)%
Average Sales Prices
Gas (per Mcf)	$	6.32		$	5.85		8%	$	7.73		$	6.04		28%
Oil (per Bbl)	$	63.54		$	50.38		26%	$	61.38		$	47.89		28%
Revenues
Gas sales	$	45,389,975		$	42,222,430		8%	$	112,794,726		$	88,800,106		27%
Oil sales	5,255,704			4,293,413			22%	9,881,003			7,644,403			29%
Total Revenues	50,645,679			46,515,843			9%	122,675,729			96,444,509			27%
Costs
Taxes, transportation and other	4,868,673			4,315,085			13%	10,596,228			8,924,224			19%
Production expense	4,778,536			4,387,547			9%	10,325,253			8,727,744			18%
Development costs(c)	12,600,000			7,200,000			75%	22,500,000			14,000,000			61%
Overhead	1,992,130			1,906,136			5%	3,990,541			3,811,791			5%
Total Costs	24,239,339			17,808,768			36%	47,412,022			35,463,759			34%
Net Proceeds	26,406,340			28,707,075			(8)%	75,263,707			60,980,750			23%
Net Profits Percentage	80		%	80		%		80		%	80		%
Net Profits Income	$	21,125,072		$	22,965,660		(8)%	$	60,210,966		$	48,784,600		23%

(a)Because of the two-month interval between time of production and receipt of net profits income by the trust, (1) oil and gas sales for the quarter ended June 30 generally represent production for the period February through April and (2) oil and gas sales for the six months ended June 30 generally represent production for the period November through April.

(b)Oil and gas sales volumes are allocated to the net profits interests based upon a formula that considers oil and gas prices and the total amount of production 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.

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The following are explanations of significant variances on the underlying properties from second quarter 2005 to second quarter 2006 and from the first six months of 2005 to the comparable period in 2006:

Sales Volumes

Gas

Gas sales volumes remained relatively unchanged for the second quarter and decreased 1% for the six-month period primarily because natural production decline was largely offset by increased production from new wells and workovers and the timing of cash receipts.

Oil

Oil sales volumes decreased 3% for the second quarter and increased 1% for the six-month period.  Fluctuations in oil sales volumes are primarily the result of natural production decline, with offsetting production from new wells and workovers and increased volumes related to the timing of cash receipts.

Sales Prices

Gas

The second quarter 2006 average gas price was $6.32 per Mcf, an 8% increase from the second quarter 2005 average gas price of $5.85 per Mcf.  For the six-month period, the average gas price increased 28% to $7.73 per Mcf in 2006 from $6.04 per Mcf in 2005.  Gas prices were higher for the second quarter and for the six-month period primarily because of increased demand and declining North American production.  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 quarter 2006 gas price is primarily related to production from February through April 2006, when the average NYMEX price was $7.23 per MMBtu, or 6% higher than the comparable 2005 period average NYMEX price of $6.80 per MMBtu.  A warmer-than-normal winter and increased gas inventories have caused recent prices to decline.  The average NYMEX price for May and June 2006 was $6.38 per MMBtu.  At July 25, 2006, the average NYMEX futures price for the following twelve months was $8.55 per MMBtu.  Recent trust gas prices have averaged approximately 15% lower than the NYMEX price.

Oil

The second quarter 2006 average oil price was $63.54 per Bbl, a 26% increase from the second quarter 2005 average oil price of $50.38 per Bbl.  The year-to-date average oil price increased 28% to $61.38 per Bbl in 2006 from $47.89 per Bbl in 2005.  Oil prices were higher for the second quarter and for the six-month period primarily because of increasing global demand and supply shortage concerns, political instability, reduced production as a result of tropical storms and hurricanes in the Gulf of Mexico in 2005 and inadequate sour crude refining capacity.  Declining oil and gasoline supplies, strong global demand and geopolitical concerns have caused recent oil prices to generally remain at or above $70.00 per Bbl.  Because of rising tension in the Middle East, oil prices increased to record levels in July 2006, exceeding $78.00 per Bbl.  The average NYMEX price for May and June 2006 was $70.94 per Bbl.  At July 25, 2006, the average NYMEX futures price for the following twelve months was $76.02 per Bbl.  Recent trust oil prices have averaged approximately 4% lower than the NYMEX price.

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Costs

Taxes

Taxes, transportation and other increased 13% for the quarter and 19% for the six-month period primarily because of increased production taxes related to higher revenues.  In addition, increased taxes, transportation and other for the six-month period was partially offset by decreased property taxes related to the timing of cash disbursements.

Production

Production expense increased 9% for the quarter and 18% for the six-month period primarily because of increased repair and maintenance, insurance and fuel costs.

Development

Development costs deducted in the calculation of net profits income are based on the development budget.  These development costs increased 75% for the second quarter and 61% for the six-month period primarily because of increased development activity in western Oklahoma as well as higher costs.  During the first half of 2006, 14 wells were completed and five wells were pending completion on the underlying properties at June 30.

As of December 31, 2005, cumulative budgeted costs deducted exceeded cumulative actual costs by approximately $114,000.  In calculating net profits income, XTO Energy deducted budgeted development costs of $12.6 million for the quarter and $22.5 million for the six-month period.  After considering actual development costs of $11.1 million for the quarter and $23.5 million for the six-month period, cumulative actual development costs exceeded budgeted development costs deducted by approximately $896,000 at June 30, 2006.

Based on the current level of development activity and continued increasing costs, XTO Energy has advised the trustee that it will increase the monthly development cost deduction from $4.2 million to $5 million beginning with the August 2006 distribution.  In addition, XTO Energy has advised the trustee that it has increased the 2006 budget from $40 million to $54 million.  The 2006 budget year generally coincides with the trust distribution months from April 2006 through March 2007.  The monthly development cost deduction will be reevaluated and revised as necessary, based on the 2006 budget and the timing and amount of actual expenditures.  See Note 2 to Condensed Financial Statements.

Overhead

Overhead increased 5% for the quarter and for the six-month period primarily because of the annual rate adjustment based on an industry index.

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Forward-Looking Statements

This Form 10-Q includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended.  All statements other than statements of historical fact included in this Form 10-Q, including, without limitation, statements regarding the net profits interests, underlying properties, development 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 I, Item 1A of the trust’s Annual Report on Form 10-K for the year ended December 31, 2005, 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, 2005.

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 functioning effectively to ensure that information required to be disclosed in reports filed with the Securities and Exchange 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.

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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, 2005.

Items 2 through 5.

Not applicable.

Item 6.Exhibits.

(a)Exhibits.

Exhibit Number
and Description
(15)	Awareness letter of KPMG LLP
(23)	Consent of Miller and Lents, Ltd.
(31)	Rule 13a-14(a)/15d-14(a) Certification
(32)	Section 1350 Certification
(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 16, 2006 (incorporated herein by reference)

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this Report to be signed on its behalf by the undersigned thereunto duly authorized.

	HUGOTON ROYALTY TRUST
	By BANK OF AMERICA, N.A., TRUSTEE
	By	/S/ NANCY G. WILLIS
		Nancy G. Willis
		Vice President
	XTO ENERGY INC.
Date: July 28, 2006	By	/S/ LOUIS G. BALDWIN
		Louis G. Baldwin
		Executive Vice President
		and Chief Financial Officer

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