HUGOTON ROYALTY TRUST - Quarter Report: 2010 September (Form 10-Q)

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 September 30, 2010

¨ 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.)

U.S. Trust, Bank of America
Private Wealth Management
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 þ No ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ¨ No ¨

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

Large accelerated filer þ	Accelerated filer ¨
Non-accelerated filer ¨ (Do not check if a smaller reporting company)	Smaller reporting company ¨

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

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

Outstanding as of October 1, 2010

40,000,000

HUGOTON ROYALTY TRUST

FORM 10-Q FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2010

	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 September 30, 2010 and December 31, 2009	6

	Condensed Statements of Distributable Income
	for the Three and Nine Months Ended September 30, 2010 and 2009	7

	Condensed Statements of Changes in Trust Corpus
	for the Three and Nine Months Ended September 30, 2010 and 2009	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 1.	Legal Proceedings	18

Item 1A.	Risk Factors	18

Item 6.	Exhibits	18

	Signatures	19

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 September 30, 2010 and the distributable income and changes in trust corpus for the three- and nine-month periods ended September 30, 2010 and 2009 have been included. Distributable income for such interim periods is not necessarily indicative of the distributable income for the full year.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Bank of America, N.A., as Trustee

for the Hugoton Royalty Trust:

We have reviewed the accompanying condensed statement of assets, liabilities and trust corpus of the Hugoton Royalty Trust as of September 30, 2010 and the related condensed statements of distributable income and changes in trust corpus for the three- and nine-month periods ended September 30, 2010 and 2009. 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, 2009, 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 2009 Annual Report on Form 10-K, and in our report dated February 22, 2010, 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, 2009 is fairly stated, in all material respects, in relation to the statement of assets, liabilities and trust corpus included in the trust’s 2009 Annual Report on Form 10-K from which it has been derived.

KPMG LLP

Fort Worth, Texas

October 25, 2010

HUGOTON ROYALTY TRUST

Condensed Statements of Assets, Liabilities and Trust Corpus

	September 30,		December 31,
	2010		2009
	(Unaudited)
ASSETS

Cash and short-term investments	$	5,316,720	$	4,284,800

Net profits interests in oil and gas properties - net (Note 1)		128,235,149		139,877,580

	$	133,551,869	$	144,162,380

LIABILITIES AND TRUST CORPUS

Distribution payable to unitholders	$	5,316,720	$	4,284,800

Trust corpus (40,000,000 units of beneficial interest authorized and outstanding)		128,235,149		139,877,580

	$	133,551,869	$	144,162,380

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
	2010		2009		2010		2009

Net profits income	$	14,695,353	$	8,533,583	$	50,568,707	$	18,848,118

Interest income		206		91		740		359

Total income		14,695,559		8,533,674		50,569,447		18,848,477

Administration expense		168,199		162,074		744,047		747,797

Distributable income	$	14,527,360	$	8,371,600	$	49,825,400	$	18,100,680

Distributable income per unit (40,000,000 units)	$	0.363184	$	0.209290	$	1.245635	$	0.452517

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
	2010			2009			2010			2009

Trust corpus, beginning of period	$	131,934,491		$	144,358,176		$	139,877,580		$	146,722,015

Amortization of net profits interests		(3,699,342	)		(1,970,183	)		(11,642,431	)		(4,334,022	)

Distributable income		14,527,360			8,371,600			49,825,400			18,100,680

Distributions declared		(14,527,360	)		(8,371,600	)		(49,825,400	)		(18,100,680	)

Trust corpus, end of period	$	128,235,149		$	142,387,993		$	128,235,149		$	142,387,993

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 (“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. On June 25, 2010, XTO Energy became a wholly owned subsidiary of Exxon Mobil Corporation. The merger is not expected to have a material effect on trust annual distributable income, financial position or liquidity. 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 $118,831,802 as of September 30, 2010 and $107,189,371 as of December 31, 2009.

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						Nine Months Ended
	September 30						September 30
	2010			2009			2010			2009
Cumulative actual costs under (over) the amount deducted – beginning of period	$	343,534		$	498,587		$	909,477		$	(7,314,084	)
Actual costs		(2,911,951	)		(856,945	)		(6,477,894	)		(10,044,274	)
Budgeted costs deducted		1,700,000			2,500,000			4,700,000			19,500,000
Cumulative actual costs (over) under the amount deducted - end of period	$	(868,417	)	$	2,141,642		$	(868,417	)	$	2,141,642

The monthly development cost deduction was $4.0 million from the January 2009 distribution through the March 2009 distribution. As a result of decreased development activity and revisions to the 2009 development budget, the development cost deduction was decreased to $2.0 million beginning with the April 2009 distribution, to $1.0 million beginning with the June 2009 distribution and to $500,000 beginning with the September 2009 distribution and was maintained at that level through the July 2010 distribution. As a result of increased development activity, the development cost deduction was increased to $600,000 beginning with the August 2010 distribution and was maintained at that level through the September 2010 distribution. As a result of increased development activity and the timing of expenditures the development cost deduction was increased to $850,000 beginning with the October 2010 distribution and is expected to be maintained at that level through the December 2010 distribution. XTO Energy has advised the trustee that revised total 2010 budgeted development costs for the underlying properties are between $8 million and $10 million. The monthly deduction is based on the current level of development expenditures, budgeted future development costs and the cumulative actual costs under (over) previous deductions. XTO Energy has advised the trustee that this monthly deduction will continue to be evaluated and revised as necessary.

3.	Contingencies

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 certain royalty owners of natural gas wells in Oklahoma and Kansas. 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. XTO Energy removed the case to federal district court in Oklahoma City. A hearing on the class certification was conducted in October 2008. At the class certification hearing, the plaintiffs sought to certify a class of royalty owners whose wells were connected to a processing plant owned by a subsidiary of XTO Energy in the Hugoton Field, with two sub-classes consisting of owners in Oklahoma and Kansas. In March 2009, the court granted the motion to certify the class. The plaintiffs filed a motion for summary judgment for only the two named plaintiffs. The court

granted the motion in the amount of $12,779. A motion for summary judgment related to the remainder of the class was denied. Trial was scheduled for April 2010; however, the court vacated the trial date. At a hearing in April 2010, the court ruled that the class representatives were no longer proper representatives and stated that it was considering whether to dismiss class counsel or decertify the class in whole or in part. In a subsequent ruling in April 2010, the court decertified the class. In April 2010, new counsel and representative parties, Fankhouser and Goddard, filed a motion to intervene and prosecute the Beer class. This motion was granted on July 13, 2010. The new plaintiffs and counsel filed an amended complaint asserting new causes of action for breach of fiduciary duties and unjust enrichment. Following an additional class discovery period, a class certification hearing was held on September 27, 2010. The court has not ruled on class certification. 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. It could, however, result in costs exceeding revenues on the properties underlying the Oklahoma and Kansas net profit interests for one or more monthly distributions, depending on the size of the judgment or settlement, if any, and the net proceeds being paid at that time.

In September 2008, a class action lawsuit was filed against XTO Energy styled Wallace B. Roderick Revocable Living Trust, et al. v. XTO Energy Inc. in the District Court of Kearny County, Kansas. XTO Energy removed the case to federal court in Wichita, Kansas. The plaintiffs allege that XTO Energy has improperly taken post-production costs from royalties paid to the plaintiffs from wells located in Kansas, Oklahoma and Colorado. The plaintiffs also seek to represent all royalty owners in these three states as a class. The plaintiffs’ claims overlap the claims made by the plaintiffs in the Beer/Fankhouser case as to certain properties. XTO Energy has answered, denying all claims, and has filed motions to dismiss a portion of the claims. In January 2010, the federal court granted XTO Energy’s motion for summary judgment concerning prior settled class actions that overlap plaintiffs’ proposed class action. The court also granted XTO Energy’s motion to dismiss those portions of plaintiffs’ class that are currently being prosecuted in the Beer/Fankhouser class action discussed above. The Roderick plaintiffs have also filed a motion to include the former Beer/Fankhouser class into this litigation. The court denied the motion. XTO Energy has informed the trustee that it believes that XTO Energy 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 the 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. It could, however, result in costs exceeding revenues on the properties underlying the Oklahoma and Kansas net profit interests for one or more monthly distributions, depending on the size of the judgment or settlement, if any, and the net proceeds being paid at that time.

In June 2010, a class action lawsuit was filed against XTO Energy styled Richard Nevins, et al. v. XTO Energy Inc., et al. in federal district court in Oklahoma City, Oklahoma. The case was administratively assigned to the same court where the Beer case was pending because the complaint purported to cover the same class as Beer. With the granting of the Fankhouser intervention, the court denied the intervention of Nevins. The time period for appeal of the ruling has passed.

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.

4.	Excess Costs

Costs exceeded revenues by $513,475 ($410,780 to the trust) on properties underlying the Kansas net profits interests in October and November 2009. Lower gas prices caused costs to exceed revenues on properties underlying the Kansas net profits interests. However, these excess costs did not reduce net proceeds from the remaining conveyances. XTO Energy advised the trustee that increased gas prices led to the partial recovery of excess costs of $410,957 ($328,766 net to the trust), plus accrued interest of $1,958 ($1,566 net to the trust) in December 2009 and the full recovery of excess costs of $102,518 ($82,014 net to the trust), plus accrued interest of $282 ($226 net to the trust) in January 2010. There were no excess costs at September 30, 2010.

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 2009 Annual Report, as well as the condensed financial statements and notes thereto included in this quarterly report on Form 10-Q. The trust’s Annual Report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and all amendments to those reports are available on the trust’s web site at www.hugotontrust.com.

Distributable Income

Quarter

For the quarter ended September 30, 2010, net profits income was $14,695,353, as compared to $8,533,583 for third quarter 2009. This 72% increase in net profits income is primarily the result of higher oil and gas prices ($7.7 million) and lower developments costs ($0.6 million), partially offset by decreased oil and gas production ($1.8 million). See “Net Profits Income” below.

After adding interest income of $206 and deducting administration expense of $168,199, distributable income for the quarter ended September 30, 2010 was $14,527,360, or $0.363184 per unit of beneficial interest. Changes in interest income are attributable to fluctuations in net profits income and interest rates. For third quarter 2009, distributable income was $8,371,600, or $0.209290 per unit. Distributions to unitholders for the quarter ended September 30, 2010 were:

		Distribution
Record Date	Payment Date	per Unit
July 30, 2010	August 13, 2010	$	0.124857
August 31, 2010	September 15, 2010		0.105409
September 30, 2010	October 15, 2010		0.132918

		$	0.363184

Nine Months

For the nine months ended September 30, 2010, net profits income was $50,568,707 compared with $18,848,118 for the same 2009 period. This 168% increase in net profits income is primarily the result of higher oil and gas prices ($29.0 million) and decreased development costs ($11.8 million), partially offset by decreased oil and gas production ($8.0 million). See “Net Profits Income” below.

After adding interest income of $740 and deducting administration expense of $744,047, distributable income for the nine months ended September 30, 2010 was $49,825,400, or $1.245635 per unit of beneficial interest. Changes in interest income are attributable to fluctuations in net profits income and interest rates. For the nine months ended September 30, 2009, distributable income was $18,100,680, or $0.452517 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									Nine Months
	Ended September 30 (a)						Increase			Ended September 30 (a)						Increase
	2010			2009			(Decrease)			2010			2009			(Decrease)
Sales Volumes
Gas (Mcf) (b)
Underlying properties		6,071,750			6,531,955			(7	)%		18,116,260			20,104,957			(10	)%
Average per day		65,997			71,000			(7	)%		66,360			73,645			(10	)%
Net profits interests		3,095,732			2,396,620			29	%		9,742,792			5,272,303			85	%

Oil (Bbls) (b)
Underlying properties		68,634			71,949			(5	)%		202,963			205,760			(1	)%
Average per day		746			782			(5	)%		743			754			(1	)%
Net profits interests		34,948			31,150			12	%		110,595			64,357			72	%

Average Sales Prices
Gas (per Mcf)	$	4.40		$	3.09			42	%	$	4.90		$	3.36			46	%
Oil (per Bbl)	$	71.43		$	56.64			26	%	$	73.55		$	47.50			55	%

Revenues
Gas sales	$	26,688,301		$	20,188,374			32	%	$	88,693,222		$	67,485,014			31	%
Oil sales		4,902,714			4,075,392			20	%		14,928,270			9,773,885			53	%

Total Revenues		31,591,015			24,263,766			30	%		103,621,492			77,258,899			34	%

Costs
Taxes, transportation and other		3,380,475			3,369,253			-			11,890,791			10,184,973			17	%
Production expense		5,374,188			5,001,346			7	%		15,506,223			16,113,262			(4	)%
Development costs (c)		1,700,000			2,500,000			(32	)%		4,700,000			19,500,000			(76	)%
Overhead		2,767,160			2,726,188			2	%		8,210,794			7,900,516			4	%
Excess costs (d)		-			-			-			102,800			-			-

Total Costs		13,221,823			13,596,787			(3	)%		40,410,608			53,698,751			(25	)%

Net Proceeds		18,369,192			10,666,979			72	%		63,210,884			23,560,148			168	%

Net Profits Percentage		80	%		80	%					80	%		80	%

Net Profits Income	$	14,695,353		$	8,533,583			72	%	$	50,568,707		$	18,848,118			168	%

(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.

(d)	See Note 4 to Condensed Financial Statements.

The following are explanations of significant variances on the underlying properties from third quarter 2009 to third quarter 2010 and from the first nine months of 2009 to the comparable period in 2010:

Sales Volumes

Gas

Gas sales volumes decreased 7% for the third quarter and 10% for the nine-month period 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 decreased 5% for the third quarter and 1% for the nine-month period primarily because of natural production decline and the timing of cash receipts, partially offset by increased production from new wells and workovers.

The rate of natural production decline on the underlying oil and gas properties is approximately 6% to 8% a year.

Sales Prices

Gas

The third quarter 2010 average gas price was $4.40 per Mcf, a 42% increase from the third quarter 2009 average gas price of $3.09 per Mcf. For the nine-month period, the average gas price increased 46% to $4.90 per Mcf in 2010 from $3.36 per Mcf in 2009. Natural gas prices are affected by the level of North American production, weather, crude oil and natural gas liquids prices, the U.S. economy, storage levels and import levels of liquefied natural gas. Natural gas prices are expected to remain volatile. The average NYMEX price for August and September 2010 was $4.21 per MMBtu. At October 20, 2010, the average NYMEX futures price for the following twelve months was $4.14 per MMBtu. Recent trust gas prices have averaged approximately 4% higher than the NYMEX price.

Oil

The third quarter 2010 average oil price was $71.43 per Bbl, a 26% increase from the third quarter 2009 average oil price of $56.64 per Bbl. The year-to-date average oil price increased 55% to $73.55 per Bbl in 2010 from $47.50 per Bbl in 2009. Oil prices are expected to remain volatile. The average NYMEX price for August and September 2010 was $76.03 per Bbl. At October 20, 2010, the average NYMEX futures price for the following twelve months was $84.54 per Bbl. Recent trust oil prices have averaged approximately 6% lower than the NYMEX price.

Costs

Taxes, Transportation and Other

Taxes, transportation and other remained relatively flat for the quarter as increased production taxes related to higher oil and gas revenues was partially offset by decreased property taxes related to lower valuations. Taxes, transportation and other increased 17% for the nine-month period primarily because of increased production taxes related to higher oil and gas revenues, partially offset by decreased other deductions as a percentage of oil and gas revenues.

Production

Production expense increased 7% for the quarter primarily due to increased repairs and maintenance, fuel and water disposal costs, partially offset by decreased compressor and plugging and abandonment costs. Production expense decreased 4% for the nine-month period primarily due to decreased compressor, chemical and treating and water disposal costs, partially offset by increased repairs and maintenance costs and decreased mechanical and marketing rebates included in 2009.

Development

Development costs deducted in the calculation of net profits income are based on the development budget. These development costs decreased 32% for the third quarter and 76% for the nine-month period primarily because of decreased development activity. During the first nine months of 2010, two wells were completed on the underlying properties and there were no wells pending completion at September 30, 2010.

As of December 31, 2009, cumulative budgeted costs deducted exceeded actual costs by approximately $0.9 million. In calculating net profits income, XTO Energy deducted budgeted development costs of $1.7 million for the quarter and $4.7 million for the nine-month period. After considering actual development costs of $2.9 million for the quarter and $6.5 million for the nine-month period, cumulative actual costs exceeded budgeted costs deducted by approximately $0.9 million at September 30, 2010.

XTO Energy has advised the trustee that total 2010 budgeted development costs for the underlying properties are approximately $8 million to $10 million. The 2010 budget year generally coincides with the trust distribution months from April 2010 through March 2011. The monthly development cost deduction will be reevaluated by XTO Energy and revised as necessary, based on the 2010 budget and the timing and amount of actual expenditures. See Note 2 to Condensed Financial Statements.

Overhead

Overhead increased 2% for the quarter and 4% for the nine-month period primarily because of the annual rate adjustment based on an industry index.

Excess Costs

Contingencies

Other

On June 25, 2010, XTO Energy became a wholly owned subsidiary of Exxon Mobil Corporation. The merger is not expected to have a material effect on trust annual distributable income, financial position or liquidity.

Forward-Looking Statements

Statements in this report relating to future plans, predictions, events or conditions are forward–looking statements. 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, monthly development cost deductions, oil and gas prices and differentials to NYMEX prices, supply levels, future drilling, workover and restimulation plans, distributions to unitholders, industry and market conditions and the impact of the merger with Exxon Mobil Corporation, 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, 2009, which is incorporated by this reference as though fully set forth herein. XTO Energy and the trustee assume no duty to update these statements as of any future date.

Item 3. Quantitative and Qualitative Disclosures about Market Risk.

There have been no material changes in the trust’s market risks from the information disclosed in Part II, Item 7A of the trust’s Annual Report on Form 10-K for the year ended December 31, 2009.

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 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 recording, processing, summarizing and reporting, on a timely basis, information required to be disclosed by the trust in the reports that it files or submits under the Securities Exchange Act of 1934 and are effective in ensuring that information required to be disclosed by the trust in the reports that it files or submits under the Securities Exchange Act of 1934 is accumulated and communicated to the trustee to allow timely decisions regarding required disclosure. In its evaluation of disclosure controls and procedures, the trustee has relied, to the extent considered reasonable, on information provided by XTO Energy. There has not been any change in the trust’s internal control over financial reporting during the period covered by this report that has materially affected, or is reasonably likely to materially affect, the trust’s internal control over financial reporting.

PART II - OTHER INFORMATION

Item 1. Legal Proceedings.

Refer to Note 3 on pages 10 through 12 of this Quarterly Report on Form 10-Q for information on legal proceedings.

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, 2009.

Items 2 through 5.

Not applicable.

Item 6.

Exhibits.

(a)

Exhibits.

Exhibit Number
and Description

(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 February 23, 2010 (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

	EXXON MOBIL CORPORATION

Date: October 25, 2010	By	/s/ Patrick T. Mulva
		Patrick T. Mulva
		Vice President and Controller