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 JuneSeptember 30, 2011

OR

¨  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
(877) 228-5083
(Registrant’s telephone number, including area code)

NONE
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  ¨  No  þ

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

Outstanding as of JulyOctober 1, 2011
40,000,000
 
 
 

HUGOTON ROYALTY TRUST

FORM 10-Q FOR THE QUARTERLY PERIOD ENDED JUNESEPTEMBER 30, 2011

TABLE OF CONTENTS

TABLE OF CONTENTS
  Page
   
 
Glossary of Terms
3
   
PART I.
FINANCIAL INFORMATION
 
   
Item 1.
Financial Statements
4
   
 
Condensed Statements of Assets, Liabilities and Trust Corpus at JuneSeptember 30, 2011 and December 31, 2010
5
   
 
Condensed Statements of Distributable Income for the Three and SixNine Months Ended JuneSeptember 30, 2011 and 2010
6
   
 
Condensed Statements of Changes in Trust Corpus for the Three and SixNine Months Ended JuneSeptember 30, 2011 and 2010
7
   
 
Notes to Condensed Financial Statements
8
   
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 2.1.
Trustee’s Discussion and Analysis
Legal Proceedings
1118
 
Item 1A.
Risk Factors
18
Item 6.
Exhibits
18
   
 Item 3.
Signatures
Quantitative and Qualitative Disclosures about Market Risk16
Item 4.Controls and Procedures16
PART II.OTHER INFORMATION
Item 1.Legal Proceedings17
Item 1A.Risk Factors17
Item 6.Exhibits17
Signatures1819

 
2
 

HUGOTON ROYALTY TRUST

GLOSSARY OF TERMS

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

BblBarrel (of oil)
  
McfThousand cubic feet (of natural gas)
  
MMBtuOne million British Thermal Units, a common energy measurement
  
net proceedsGross 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 incomeNet 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 interestAn 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 propertiesXTO 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 interestAn 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

 
3
 

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 financial statements and the notes thereto included in the trust’s latest 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 JuneSeptember 30, 2011 and the distributable income and changes in trust corpus for the three- and six-monthnine-month periods ended JuneSeptember 30, 2011 and 2010 have been included.  Distributable income for such interim periods is not necessarily indicative of the distributable income for the full year.

 
4
 

HUGOTON ROYALTY TRUST

Condensed Statements of Assets, Liabilities and Trust Corpus

 June 30,  December 31,  September 30,  December 31, 
 2011  2010  2011  2010 
 (Unaudited)     (Unaudited)    
ASSETS            
            
Cash and short-term investments $5,305,400  $4,229,120  $5,336,520  $4,229,120 
                
Net profits interests in oil and gas properties - net (Note 1)  120,236,128   124,993,766   117,672,381   124,993,766 
                
 $125,541,528  $129,222,886  $123,008,901  $129,222,886 
                
LIABILITIES AND TRUST CORPUS                
                
Distribution payable to unitholders $5,305,400  $4,229,120  $5,336,520  $4,229,120 
                
Trust corpus (40,000,000 units of beneficial interest authorized and outstanding)  120,236,128   124,993,766   117,672,381   124,993,766 
                
 $125,541,528  $129,222,886  $123,008,901  $129,222,886 

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

 
5
 

HUGOTON ROYALTY TRUST

Condensed Statements of Distributable Income (Unaudited)

 Three Months Ended  Six Months Ended  Three Months Ended  Nine Months Ended 
 June 30  June 30  September 30  September 30 
 2011  2010  2011  2010  2011  2010  2011  2010 
                        
Net profits income $14,667,930  $18,974,132  $27,882,028  $35,873,354  $15,477,314  $14,695,353  $43,359,342  $50,568,707 
                                
Interest income  171   432   456   534   355   206   811   740 
                                
Total income  14,668,101   18,974,564   27,882,484   35,873,888   15,477,669   14,695,559   43,360,153   50,569,447 
                                
Administration expense  265,341   241,644   539,724   575,848   144,309   168,199   684,033   744,047 
                                
Distributable income $14,402,760  $18,732,920  $27,342,760  $35,298,040  $15,333,360  $14,527,360  $42,676,120  $49,825,400 
                                
Distributable income per unit (40,000,000 units)
 $0.360069  $0.468323  $0.683569  $0.882451  $0.383334  $0.363184  $1.066903  $1.245635 

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  Three Months Ended  Nine Months Ended 
 June 30  June 30  September 30  September 30 
 2011  2010  2011  2010  2011  2010  2011  2010 
                        
Trust corpus, beginning of period $122,620,884  $136,036,821  $124,993,766  $139,877,580  $120,236,128  $131,934,491  $124,993,766  $139,877,580 
                                
Amortization of net profits interests  (2,384,756)  (4,102,330)  (4,757,638)  (7,943,089)  (2,563,747)  (3,699,342)  (7,321,385)  (11,642,431)
                                
Distributable income  14,402,760   18,732,920   27,342,760   35,298,040   15,333,360   14,527,360   42,676,120   49,825,400 
                                
Distributions declared  (14,402,760)  (18,732,920)  (27,342,760)  (35,298,040)  (15,333,360)  (14,527,360)  (42,676,120)  (49,825,400)
                                
Trust corpus, end of period $120,236,128  $131,934,491  $120,236,128  $131,934,491  $117,672,381  $128,235,149  $117,672,381  $128,235,149 

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

 
7
 

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.  XTO Energy is a wholly owned subsidiary of Exxon Mobil Corporation.  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 the 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 $126,830,823$129,394,570 as of JuneSeptember 30, 2011 and $122,073,185 as of December 31, 2010.

 
8
 


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  Three Months Ended  Nine Months Ended 
 June 30  June 30  September 30  September 30 
 2011  2010  2011  2010  2011  2010  2011  2010 
Cumulative actual costs (over) under the amount deducted - beginning of period $(56,755) $989,364  $(809,696) $909,477 
Cumulative actual costs under (over) the amount deducted - beginning of period
 $1,500,347  $343,534  $(809,696) $909,477 
Actual costs  (992,898)  (2,145,830)  (2,789,957)  (3,565,943)  (1,287,129)  (2,911,951)  (4,077,086)  (6,477,894)
Budgeted costs deducted  2,550,000   1,500,000   5,100,000   3,000,000   2,200,000   1,700,000   7,300,000   4,700,000 
Cumulative actual costs under the amount deducted - end of period $1,500,347  $343,534  $1,500,347  $343,534 
Cumulative actual costs under (over) the amount deducted - end of period
 $2,413,218  $(868,417) $2,413,218  $(868,417)

The monthly development cost deduction was $500,000 from the January 2010 distribution 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 to $850,000 beginning with the October 2010 distribution and was maintained at that level through the JuneAugust 2011 distribution.  Due to lower than anticipated actual costs as a result of the timing of expenditures, the development cost deduction was decreased to $500,000 beginning with the September 2011 distribution and is expected to be maintained at that level for the remainder of 2011.  XTO Energy has advised the trustee that totalrevised 2011 budgeted development costs for the underlying properties are between $10$8 million and $12$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. Federal Income Taxes

For federal income tax purposes, the trust constitutes a fixed investment trust which is taxed as a grantor trust.  A grantor trust is not subject to tax at the trust level.  The unitholders are considered to own the trust’s income and principal as though no trust were in existence.  The income of the trust is deemed to have been received or accrued by each unitholder at the time such income is received or accrued by the trust and not when distributed by the trust.

The net profits interests constitute “economic interests” in oil and gas properties for federal income tax purposes.  Unitholders must report their share of the net profits income as ordinary income from oil and gas properties and are entitled to claim depletion with respect to such income.  The classification of the trust’s income for purposes of the passive loss rules may be important to a unitholder.  Net profits income generally is treated as portfolio income and does not offset passive losses.

 
9
 

Some trust units are held by middlemen, as such term is broadly defined in U.S. Treasury Regulations (and includes custodians, nominees, certain joint owners, and brokers holding an interest for a customer in street name, collectively referred to herein as “middlemen”).  Therefore, the trustee considers the trust to be a non-mortgage widely held fixed investment trust (“WHFIT”) for U.S. federal income tax purposes.  U.S. Trust, Bank of America Private Wealth Management, EIN: 56-0906609, Post Office Box 830650, Dallas, Texas. 75283-0650, telephone number 1-877-228-5083, email address trustee@hugotontrust.com, is the representative of the trust that will provide tax information in accordance with applicable U.S. Treasury Regulations governing the information reporting requirements of the trust as a WHFIT.  Tax information is also posted by the trustee at www.hugotontrust.com.  Notwithstanding the foregoing, the middlemen holding trust units on behalf of unitholders, and not the trustee of the trust, are solely responsible for complying with the information reporting requirements under the U.S. Treasury Regulations with respect to such trust units, including the issuance of IRS Forms 1099 and certain written tax statements.  Unitholders whose trust units are held by middlemen should consult with such middlemen regarding the information that will be reported to them by the middlemen with respect to the trust units.

Unitholders should consult their tax advisors regarding trust tax compliance matters.

4. State Income Taxes

All revenues from the trust are from sources within either Kansas, Oklahoma or Wyoming.  Oklahoma and Kansas tax the income of nonresidents from real property located within those states, and the trust has been advised by counsel that those states will each tax nonresidents on income from the net profits interests located in those states.  Wyoming does not have a state income tax.  Kansas and Oklahoma also impose a corporate income tax which may apply to unitholders organized as corporations.

Each unitholder should consult his or her own tax advisor regarding state income tax requirements, if any, applicable to such person’s ownership of trust units.

5. 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. In April 2010, new counsel and representative parties, Fankhouser and Goddard, filed a motion to intervene and prosecute the Beer class, now styled Fankhouser v. XTO Energy Inc.  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.  On December 16, 2010, the court certified the class.  XTO Energy has informed the trustee that it believes that it has strong defenses to this lawsuit and intends to vigorously defend its position.

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 have filed a motion to certify the class, including only Kansas and Oklahoma wells not part of the Fankhouser matter.  After filing the motion to certify, but prior to the class certification hearing, Plaintiffplaintiff filed a motion to sever the Oklahoma portion of the case so it could be transferred and consolidated with a newly filed class action in Oklahoma styled Chieftain v. XTO Energy Inc.  This motion was granted.  The Roderick case now comprises only Kansas wells not previously included in the Fankhouser matter.  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.

10

In December 2010, a class action lawsuit was filed against XTO Energy styled Chieftain Royalty Company vs. XTO Energy Inc. in Coal County District Court, Oklahoma.  XTO Energy removed the case to federal court in the Eastern District of Oklahoma.  The Plaintiffsplaintiffs allege that XTO Energy wrongfully deducted fees from royalty payments on Oklahoma wells, failed to make diligent efforts to secure the best terms available for the sale of gas and its constituents, and demand an accounting to determine whether they have been fully and fairly paid gas royalty interests.  The case expressly excludes those claims and wells being prosecuted in the Fankhouser case.  The severed Roderick case claims will likely berelated to the Oklahoma portion of the case were consolidated into Chieftain.  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.

10

If XTO Energy ultimately makes any settlement payments or receives a judgment against it in any of the cases named above, 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.  Itliquidity though it could however,be material to the trust’s annual distributable income.  Additionally, it could 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.

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 requiring state income tax withholding from nonresident recipients of oil and gas proceeds.  After consultation with its tax counsel, the trustee believes that it is not required to withhold on payments made to the unitholders.  However, regulations are subject to change by the various states, which could change this conclusion.  Should withholdingamounts be requiredwithheld on payments made to the trust or the unitholders, distributions to the unitholders would be reduced by the required amount, subject to the filing of a claim for refund by the trust or unitholders for such amount.

5.    
6. Excess Costs

Costs exceeded revenues by $513,475 ($410,780 net 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 as of JuneSeptember 30, 2011.

11

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 2010 Annual Report on Form 10-K, 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.

11

Distributable Income

Quarter

For the quarter ended JuneSeptember 30, 2011, net profits income was $14,667,930,$15,477,314, as compared to $18,974,132$14,695,353 for secondthird quarter 2010.  This 23% decrease5% increase in net profits income is primarily the result of decreased gashigher oil and oil sales volumes ($3.7 million), lower gas prices ($1.5 million) and higher development costs ($0.84.0 million), partially offset by increaseddecreased oil pricesand gas sales volumes ($1.13.0 million) and lower taxes, transportation and otherincreased development costs ($0.70.4 million). See “Net Profits Income” on following page.

After adding interest income of $171$355 and deducting administration expense of $265,341,$144,309, distributable income for the quarter ended JuneSeptember 30, 2011 was $14,402,760,$15,333,360, or $0.360069$0.383334 per unit of beneficial interest. Administration expense for the quarter was higher thandecreased $23,890 from the prior year quarter primarily because of the timing of expenditures.quarter.  For secondthird quarter 2010, distributable income was $18,732,920,$14,527,360, or $0.468323$0.363184 per unit.  Distributions to unitholders for the quarter ended JuneSeptember 30, 2011 were:

    Distribution 
Record Date Payment Date per Unit 
April 29, 2011 May 13, 2011 $0.102412 
May 31, 2011 June 14, 2011  0.125022 
June 30, 2011 July 15, 2011  0.132635 
    $0.360069 
    Distribution 
Record Date Payment Date per Unit 
July 29, 2011 August 12, 2011 $0.128296 
August 31, 2011 September 15, 2011  0.121625 
September 30, 2011 October 17, 2011  0.133413 
       
    $0.383334 

SixNine Months

For the sixnine months ended JuneSeptember 30, 2011, net profits income was $27,882,028$43,359,342 compared with $35,873,354$50,568,707 for the same 2010 period.  This 22%14% decrease in net profits income is primarily the result of decreased oil and gas sales volumes ($7.2 million), lower gas prices ($5.0 million), decreased gas sales volumes ($4.12.3 million) and higher development costs ($1.72.1 million), partially offset by higher oil prices ($1.83.0 million) and lower taxes, transportation and other costs ($1.41.3 million).  See “Net Profits Income” on following page.

After adding interest income of $456$811 and deducting administration expense of $539,724,$684,033, distributable income for the sixnine months ended JuneSeptember 30, 2011 was $27,342,760,$42,676,120, or $0.683569$1.066903 per unit of beneficial interest.  Administration expense for the sixnine months ended JuneSeptember 30, 2011 was lowerdecreased $60,014 as compared with the same 2010 period primarily because of decreased costs and the timing of expenditures.period.  For the sixnine months ended JuneSeptember 30, 2010, distributable income was $35,298,040,$49,825,400, or $0.882451$1.245635 per unit.

12

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.

 
1213
 

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

 Three Months     Six Months     Three Months     Nine Months    
 
Ended June 30 (a)
  Increase 
Ended June 30 (a)
  Increase 
Ended September 30 (a)
  Increase 
Ended September 30 (a)
  Increase
 2011  2010  (Decrease) 2011  2010  (Decrease) 2011  2010  (Decrease) 2011  2010  (Decrease)
Sales Volumes                                    
Gas (Mcf) (b)
                                    
Underlying properties  5,299,946   6,113,559   (13)%  10,935,280   12,044,510   (9)%  5,516,991   6,071,750   (9)%  16,452,271   18,116,260   (9)%
Average per day  59,550   68,692   (13)%  60,416   66,544   (9)%  59,967   65,997   (9)%  60,265   66,360   (9)%
Net profits interests  2,641,356   3,432,982   (23)%  5,269,357   6,647,060   (21)%  2,839,604   3,095,732   (8)%  8,108,961   9,742,792   (17)%
                                                
Oil (Bbls) (b)
                                                
Underlying properties  64,010   71,105   (10)%  132,185   134,329   (2)%  58,527   68,634   (15)%  190,712   202,963   (6)%
Average per day  719   799   (10)%  730   742   (2)%  636   746   (15)%  699   743   (6)%
Net profits interests  33,993   41,321   (18)%  67,760   75,647   (10)%  31,574   34,948   (10)%  99,334   110,595   (10)%
                                                
Average Sales Prices                                                
Gas (per Mcf) $4.86  $5.17   (6)% $4.63  $5.15   (10)% $4.96  $4.40   13% $4.74  $4.90   (3)%
Oil (per Bbl) $96.92  $77.03   26% $90.95  $74.63   22% $95.00  $71.43   33% $92.19  $73.55   25%
                                                
Revenues                                                
Gas sales $25,740,672  $31,609,753   (19)% $50,591,936  $62,004,921   (18)% $27,374,742  $26,688,301   3% $77,966,678  $88,693,222   (12)%
Oil sales  6,203,994   5,477,186   13%  12,022,070   10,025,556   20%  5,559,851   4,902,714   13%  17,581,921   14,928,270   18%
Total Revenues  31,944,666   37,086,939   (14)%  62,614,006   72,030,477   (13)%  32,934,593   31,591,015   4%  95,548,599   103,621,492   (8)%
                                                
Costs                                                
Taxes, transportation and other
  3,443,176   4,319,945   (20)%  6,764,671   8,510,316   (21)%  3,514,793   3,380,475   4%  10,279,464   11,890,791   (14)%
Production expense  4,911,651   4,825,144   2%  10,482,090   10,132,035   3%  5,173,918   5,374,188   (4)%  15,656,008   15,506,223   1%
Development costs (c)
  2,550,000   1,500,000   70%  5,100,000   3,000,000   70%  2,200,000   1,700,000   29%  7,300,000   4,700,000   55%
Overhead  2,704,927   2,724,185   (1)%  5,414,710   5,443,634   (1)%  2,699,240   2,767,160   (2)%  8,113,950   8,210,794   (1)%
Excess costs (d)
  -   -   -   -   102,800   -   -   -   -   -   102,800   - 
Total Costs  13,609,754   13,369,274   2%  27,761,471   27,188,785   2%  13,587,951   13,221,823   3%  41,349,422   40,410,608   2%
                                                
Net Proceeds  18,334,912   23,717,665   (23)%  34,852,535   44,841,692   (22)%  19,346,642   18,369,192   5%  54,199,177   63,210,884   (14)%
                                                
Net Profits Percentage  80%  80%      80%  80%      80%  80%      80%  80%    
                                                
Net Profits Income $14,667,930  $18,974,132   (23)% $27,882,028  $35,873,354   (22)% $15,477,314  $14,695,353   5% $43,359,342  $50,568,707   (14)%

(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 JuneSeptember 30 generally represent production for the period FebruaryMay through AprilJuly  and (2) oil and gas sales for the sixnine months ended JuneSeptember 30 generally represent production for the period November through April.July.

(b)
Oil and gas sales volumes are allocated to the net profits interests based upon a formula that considers oil and gas prices and the total amount of production expense and development costs.  As product prices change, the trust’s share of the production volumes is impacted as the quantity of production to cover expenses in reaching the net profits break-even level changes inversely with price.  As such, the underlying property production volume changes may not correlate with the trust’s net profit share of those volumes in any given period.  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 56 to Condensed Financial Statements.

 
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The following are explanations of significant variances on the underlying properties from secondthird quarter 2010 to secondthird quarter 2011 and from the first sixnine months of 2010 to the comparable period in 2011:

Sales Volumes

Gas

Gas sales volumes decreased 13%9% for secondthird quarter 2011 and for the first nine months of 2011 as compared with the same 2010 periodperiods primarily because of natural production decline.

Oil

Oil sales volumes decreased 15% for third quarter 2011 and 6% for the first nine months of 2011 as compared with the same 2010 periods primarily because of natural production decline and the timing of cash receipts.  Gas sales volumes decreased 9% for the first six months of 2011 as compared with the same 2010 period primarily because of natural production decline, partially offset by increased production from new wells and workovers.

Oil

Oil sales volumes decreased 10% for second quarter 2011 as compared with the same 2010 period primarily because of the timing of cash receipts and natural production decline, partially offset by increased production from new wells and workovers. Oil sales volumes decreased 2% for the first six months of 2011 as compared with the same 2010 period primarily because of natural production decline, 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 secondthird quarter 2011 average gas price was $4.86$4.96 per Mcf, a 6% decrease13% increase from the secondthird quarter 2010 average gas price of $5.17$4.40 per Mcf.  For the six-monthnine-month period, the average gas price decreased 10%3% to $4.63$4.74 per Mcf in 2011 from $5.15$4.90 per Mcf in 2010.  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 secondthird quarter 2011 gas price is primarily related to production from FebruaryMay through AprilJuly 2011, when the average NYMEX price was $4.12$4.35 per MMBtu.  The average NYMEX price for MayAugust and JuneSeptember 2011 was $4.35$4.11 per MMBtu.  At July 18,October 13, 2011, the average NYMEX futures price for the following twelve months was $4.74$3.98 per MMBtu.

Oil

The secondthird quarter 2011 average oil price was $96.92$95.00 per Bbl, a 26%33% increase from the secondthird quarter 2010 average oil price of $77.03$71.43 per Bbl.  The year-to-date average oil price increased 22%25% to $90.95$92.19 per Bbl in 2011 from $74.63$73.55 per Bbl in 2010.  Oil prices are expected to remain volatile.  The secondthird quarter 2011 oil price is primarily related to production from FebruaryMay through AprilJuly 2011, when the average NYMEX price was $101.00$98.15 per Bbl.  The average NYMEX price for MayAugust and JuneSeptember 2011 was $98.69$85.78 per Bbl.  At July 18,October 13, 2011, the average NYMEX futures price for the following twelve months was $98.32$85.59 per Bbl.

 
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Costs

Taxes, Transportation and Other

Taxes, transportation and other increased 4% for the quarter primarily due to increased production taxes related to higher oil and gas revenues. Taxes, transportation and other decreased 20%14% for the quarter and 21% for the six-monthnine-month period primarily because of decreased property taxes related to the timing of expenditures and decreased gas production taxes related to lower gas revenues, and decreased property taxes related to the timing of expenditures, partially offset by increased oil production taxes related to higher oil revenues.

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Production Expense

Production expense increased 2%decreased 4% for the quarter primarily because of increasedmarketing and economic rebates included in 2011, decreased insurance, labor compressor rental and fieldlocation costs, partially offset by decreased repairsincreased power and maintenance costs and mechanical and marketing rebates included in 2011.  Production expense increased 3% for the six-month period primarily because of increased labor,fuel, field and water disposal costs, partially offset by decreased repairs and maintenance, plugging and abandonment, chemical and treating and mechanical and marketing rebates included in 2011.compressor rental costs.

Development

Development costs deducted in the calculation of net profits income are based on the development budget.  These development costs increased 70%29% for the secondthird quarter and 55% for the six-monthnine-month period primarily because of increased development activity and the timing of expenditures.

As of December 31, 2010, cumulative actual costs exceeded cumulative budgeted costs by approximately $0.8 million. In calculating net profits income for the quarter ended JuneSeptember 30, 2011, XTO Energy deducted budgeted development costs of $2.6$2.2 million for the quarter and $5.1$7.3 million for the six-monthnine-month period.  After considering actual development costs of $1.0$1.3 million for the quarter and $2.8$4.1 million for the six-monthnine-month period, budgeted costs deducted exceeded cumulative actual costs by approximately $1.5$2.4 million at JuneSeptember 30, 2011.

XTO Energy has advised the trustee that totalrevised 2011 budgeted development costs for the underlying properties are between $10$8 million and $12$10 million.  The 2011 budget year generally coincides with the trust distribution months from April 2011 through March 2012.  The monthly development cost deduction will be reevaluated by XTO Energy and revised as necessary, based on the 2011 budget and the timing and amount of actual expenditures.  See Note 2 to Condensed Financial Statements.

Excess Costs

Costs exceeded revenues by $513,475 ($410,780 net 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 as of JuneSeptember 30, 2011.

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Contingencies

Several states have enacted legislation requiring state income tax withholding from nonresident recipients of oil and gas proceeds.  After consultation with its tax counsel, the trustee believes that it is not required to withhold on payments made to the unitholders.  However, regulations are subject to change by the various states, which could change this conclusion.  Should withholdingamounts be requiredwithheld on payments made to the trust or the unitholders, distributions to the unitholders would be reduced by the required amount, subject to the filing of a claim for refund by the trust or unitholders for such amount.

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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 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, 2010, which is incorporated by this reference as though fully set forth herein.  XTO Energy, ExxonMobil 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, 2010.

Item 4.  Controls and Procedures.
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.

 
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PART II - OTHER INFORMATION

Item 1.  Legal Proceedings.

Refer to Note 35 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, 2010.

Items 2 through 5.

Not applicable.

Item 6.   Exhibits.
Item 6.
Exhibits.

 (a)Exhibits.

Exhibit Number
and Description

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 24, 2011 (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
  
 EXXON MOBIL CORPORATION
  
Date:  August 1,October 27, 2011By/s/ Patrick T. Mulva
  Patrick T. Mulva
  Vice President and Controller
 
 
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