Unassociated Document
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, 2008
 
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
(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 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, 2008
40,000,000


HUGOTON ROYALTY TRUST

FORM 10-Q FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2008

  TABLE OF CONTENTS   
     
   
Page
     
 
     
 
     
   
 
 
     
 
   
 
 
     
 
     
 
     
     
     
     
 
     
     
     
 

2

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

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 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, 2008 and the distributable income and changes in trust corpus for the three- and nine-month periods ended September 30, 2008 and 2007 have been included. Distributable income for such interim periods is not necessarily indicative of the distributable income for the full year.

4
 
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, 2008 and the related condensed statements of distributable income and changes in trust corpus for the three- and nine-month periods ended September 30, 2008 and 2007. 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, 2007, 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 2007 Annual Report on Form 10-K, and in our report dated February 25, 2008, 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, 2007 is fairly stated, in all material respects, in relation to the statement of assets, liabilities and trust corpus included in the trust’s 2007 Annual Report on Form 10-K from which it has been derived.

KPMG LLP

Fort Worth, Texas
October 29, 2008

5

HUGOTON ROYALTY TRUST

Condensed Statements of Assets, Liabilities and Trust Corpus

   
September 30,
  
December 31,
  
   
2008
  
2007
  
   
(Unaudited)
      
ASSETS
              
               
Cash and short-term investments
  
$
16,177,840
  
$
5,214,000
  
               
Net profits interests in oil and gas properties - net (Note 1)
    
148,258,868
    
155,820,033
  
               
   
$
164,436,708
  
$
161,034,033
  
               
LIABILITIES AND TRUST CORPUS
              
               
Distribution payable to unitholders
  
$
16,177,840
  
$
5,214,000
  
               
Trust corpus (40,000,000 units of beneficial interest authorized and outstanding)
    
148,258,868
    
155,820,033
  
               
   
$
164,436,708
  
$
161,034,033
  

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

6

HUGOTON ROYALTY TRUST

Condensed Statements of Distributable Income (Unaudited)

   
Three Months Ended 
September 30
  
Nine Months Ended 
September 30
  
   
2008
  
2007
  
2008
  
2007
  
                   
Net profits income
  
$
43,741,409
  
$
17,870,756
  
$
99,676,511
  
$
55,857,387
  
                           
Interest income
    
31,050
    
38,226
    
73,801
    
107,395
  
                           
Total income
    
43,772,459
    
17,908,982
    
99,750,312
    
55,964,782
  
                           
Administration expense
    
83,819
    
174,302
    
737,592
    
1,141,822
  
                           
Distributable income
  
$
43,688,640
  
$
17,734,680
  
$
99,012,720
  
$
54,822,960
  
                           
Distributable income per unit (40,000,000 units)
  
$
1.092216
  
$
0.443367
  
$
2.475318
  
$
1.370574
  

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

7

HUGOTON ROYALTY TRUST

Condensed Statements of Changes in Trust Corpus (Unaudited)

   
Three Months Ended 
September 30
  
Nine Months Ended 
September 30
  
   
2008
  
2007
  
2008
  
2007
  
                   
Trust corpus, beginning of period
  
$
151,013,766
  
$
159,594,894
  
$
155,820,033
  
$
163,796,772
  
                           
Amortization of net profits interests
    
(2,754,898
)
  
(2,061,219
)
  
(7,561,165
)
  
(6,263,097
)
                           
Distributable income
    
43,688,640
    
17,734,680
    
99,012,720
    
54,822,960
  
                           
Distributions declared
    
(43,688,640
)
  
(17,734,680
)
  
(99,012,720
)
  
(54,822,960
)
                           
Trust corpus, end of period
  
$
148,258,868
  
$
157,533,675
  
$
148,258,868
  
$
157,533,675
  

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

8

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”):

 
B
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.

 
B
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.

 
B
Trust expenses are recorded based on liabilities paid and cash reserves established by the trustee for liabilities and contingencies.

 
B
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 $98,808,083 as of September 30, 2008 and $91,246,918 as of December 31, 2007.

9

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
September 30
  
Nine Months Ended
September 30
  
   
2008
 
2007
 
2008
 
2007
 
Cumulative actual costs under (over) the amount deducted - beginning of period
  
$
4,729,172
  
$
3,050,773
  
$
(675,754
)
$
(3,410,174
)
Actual costs
    
(19,937,960
)
  
(11,843,853
)
  
(37,033,034
)
  
(25,632,906
)
Budgeted costs deducted
    
11,500,000
    
11,250,000
    
34,000,000
    
31,500,000
  
 
$
(3,708,788
)
$
2,456,920
  
$
(3,708,788
)
$
2,456,920
  

Based on the development budget for 2007, the development cost deduction was lowered to $3.75 million per month beginning with the February 2007 distribution. Due to lower than anticipated actual costs as a result of the timing of expenditures, the development cost deduction was lowered to $2.0 million for the April and May 2007 distributions, but was increased to $3.75 million with the June 2007 distribution and was maintained at $3.75 million for the remainder of 2007 through the August 2008 distribution. Due to higher than anticipated costs as a result of the timing of expenditures, the monthly development cost deduction was increased to $4.0 million beginning with the September 2008 distribution and is expected to be maintained at that level for the remainder of 2008.

XTO Energy has advised the trustee that total 2008 budgeted development costs for the underlying properties are approximately $46.0 million. The 2008 budget year generally coincides with the trust distribution months from April 2008 through March 2009. The monthly development cost deduction will be reevaluated by XTO Energy and revised as necessary, based on the 2008 budget and the timing and amount of actual expenditures.

3.
Contingencies

Litigation

On October 17, 1997, an action, styled United States of America ex rel. Grynberg v. Cross Timbers Oil Company, et 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 measuring practices. This lawsuit against XTO Energy and similar lawsuits filed by Grynberg against more than 300 other companies was consolidated in the United States District Court for Wyoming. In October 2002, the court granted a motion to dismiss Grynberg’s royalty valuation claims, and Grynberg’s appeal of this decision was dismissed for lack of appellate jurisdiction in May 2003. In response to a motion to dismiss filed by XTO Energy and other defendants, in October 2006 the district judge held that Grynberg failed to establish the jurisdictional requirements to maintain the action against XTO Energy and other defendants and dismissed the actions for lack of subject matter jurisdiction. Grynberg has filed an appeal of this decision. While XTO Energy is unable to predict the final outcome of this case or estimate the amount of any possible loss, it has informed the trustee that it believes that the allegations of this lawsuit are without merit and intends to vigorously defend the action. However, an order to change measuring practices or a related settlement could adversely affect the trust by reducing net proceeds in the future by an amount that is presently not determinable, but, in XTO Energy management’s opinion, is not currently expected to be material to the trust’s annual distributable income, financial position or liquidity.

10

An amended petition for a class action lawsuit, Beer, et al. v. XTO Energy Inc., was filed in January 2006, in the District Court of Texas County, Oklahoma by royalty owners of natural gas wells in Oklahoma. The plaintiffs allege that XTO Energy has not properly accounted to the plaintiffs for the royalties to which they are entitled and seek an accounting regarding the natural gas and other products produced from their wells and the prices paid for the natural gas and other products produced, and for payment of the monies allegedly owed since June 2002, with a certain limited number of plaintiffs claiming monies owed for additional time. XTO Energy removed the case to federal district court in Oklahoma City. A hearing on the class certification was held in October 2008. XTO Energy is waiting for the court’s ruling. The plaintiffs have not alleged in their petition an amount that they are seeking. XTO Energy has informed the trustee that it believes that it has strong defenses to this lawsuit and intends to vigorously defend its position. However, if XTO Energy ultimately makes any settlement payments or receives a judgment against it, the trust will bear its 80% share of such settlement or judgment related to production from the underlying properties. Additionally, if a judgment or settlement increases the amount of future payments to royalty owners, the trust would bear its proportionate share of the increased payments through reduced net proceeds. XTO Energy has informed the trustee that, although the amount of any reduction in net proceeds is not presently determinable, in its management’s opinion, the amount is not currently expected to be material to the trust’s annual distributable income, financial position or liquidity.  

Certain of the underlying properties are involved in various other lawsuits and certain governmental proceedings arising in the ordinary course of business. XTO Energy has advised the trustee that it does not believe that the ultimate resolution of these claims will have a material effect on trust annual distributable income, financial position or liquidity.

Other

Several states have enacted legislation to require state income tax withholding from nonresident recipients of oil and gas proceeds. After consultation with its state tax counsel, XTO Energy has advised the trustee that it believes the trust is not subject to these withholding requirements. However, regulations could be issued by the various states which could change this conclusion. Should the trust be required to withhold state taxes, distributions to the unitholders would be reduced by the required amount, subject to the unitholder’s right to file a state tax return to claim any refund due.

4.
Excess Costs

Costs exceeded revenues by $853,468 ($682,774 net to the trust) on properties underlying the Wyoming net profits interests in November and December 2007. Limited pipeline capacity for shipping from the Rocky Mountain region and excess regional supply led to significantly lower realized regional gas prices for production. These lower gas prices caused costs to exceed revenues on properties underlying the Wyoming net profits interests, however, these excess costs did not reduce net proceeds from the remaining conveyances.

XTO Energy advised the trustee that with the onset of winter demand and the completion of the first phase of a major pipeline expansion in January 2008, Rocky Mountain gas prices increased and the excess costs, plus accrued interest of $10,090 ($8,072 net to the trust), were fully recovered by February 2008.
 
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 2007 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, 2008, net profits income was $43,741,409, as compared to $17,870,756 for third quarter 2007. This 145% increase in net profits income is primarily the result of higher oil and gas prices and higher oil and gas production, partially offset by higher taxes, transportation and other costs and increased production expense. See “Net Profits Income” on the following page.

After adding interest income of $31,050 and deducting administration expense of $83,819, distributable income for the quarter ended September 30, 2008 was $43,688,640, or $1.092216 per unit of beneficial interest. Administration expense for the quarter was lower than the prior year quarter primarily because of the timing of expenditures. For third quarter 2007, distributable income was $17,734,680, or $0.443367 per unit. Distributions to unitholders for the quarter ended September 30, 2008 were:

Record Date
  
Payment Date
  
Distribution
per Unit
  
July 31, 2008
    
August 14, 2008
  
$
0.359084
  
August 29, 2008
    
September 15, 2008
    
0.328686
  
September 30, 2008
    
October 15, 2008
    
0.404446
  
               
         
$
1.092216
  

Nine Months

For the nine months ended September 30, 2008, net profits income was $99,676,511 compared with $55,857,387 for the same 2007 period. This 78% increase in net profits income is primarily the result of higher oil and gas prices and higher oil and gas production, partially offset by higher taxes, transportation and other costs, increased production expense and higher development costs. See “Net Profits Income” on the following page.

After adding interest income of $73,801 and deducting administration expense of $737,592, distributable income for the nine months ended September 30, 2008 was $99,012,720, or $2.475318 per unit of beneficial interest. Administration expense for the first nine months of 2008 was lower than in the first nine months of 2007 primarily because of lower costs related to unitholder tax reporting, as a result of a decrease in the number of unitholders, and the timing of expenditures. For the nine months ended September 30, 2007, distributable income was $54,822,960, or $1.370574 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.
 
13

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
  
   
2008
  
2007
  
(Decrease)
  
2008
  
2007
  
(Decrease)
  
Sales Volumes
                                      
Gas (Mcf) (b)
                                      
Underlying properties
    
7,100,403
    
6,980,106
    
2
%
  
21,368,077
    
20,838,899
    
3
%
Average per day
    
77,178
    
75,871
    
2
%
  
77,986
    
76,333
    
2
%
Net profits interests
    
3,977,121
    
2,903,001
    
37
%
  
10,915,817
    
8,820,209
    
24
%
                                       
Oil (Bbls) (b)
                                      
Underlying properties
    
94,751
    
76,832
    
23
%
  
263,779
    
223,555
    
18
%
Average per day
    
1,030
    
835
    
23
%
  
963
    
819
    
18
%
Net profits interests
    
55,308
    
33,044
    
67
%
  
140,239
    
106,310
    
32
%
                                       
Average Sales Prices
                                      
Gas (per Mcf)
  
$
10.15
  
$
5.93
    
71
%
$
8.29
  
$
6.02
    
38
%
Oil (per Bbl)
  
$
125.74
  
$
65.14
    
93
%
$
108.41
  
$
60.41
    
79
%
                                       
Revenues
                                      
Gas sales
  
$
72,074,994
   
$
41,401,782
    
74
%
$
177,195,695
  
$
125,515,708
    
41
%
Oil sales
    
11,913,831
    
5,005,105
    
138
%
  
28,595,710
    
13,505,539
    
112
%
                                       
Total Revenues
    
83,988,825
    
46,406,887
    
81
%
  
205,791,405
    
139,021,247
    
48
%
                                       
Costs
                                      
Taxes, transportation and other
    
7,187,902
    
4,642,514
    
55
%
  
18,627,823
    
14,096,130
    
32
%
Production expense
    
8,031,499
    
5,860,762
    
37
%
  
20,425,623
    
16,876,291
    
21
%
Development costs (c)
    
11,500,000
    
11,250,000
    
2
%
  
34,000,000
    
31,500,000
    
8
%
Overhead
    
2,592,663
    
2,315,166
    
12
%
  
7,278,762
    
6,727,092
    
8
%
Excess costs (d)
    
-
    
-
    
-
    
863,558
    
-
    
-
  
                                       
Total Costs
    
29,312,064
    
24,068,442
    
22
%
  
81,195,766
    
69,199,513
    
17
%
                                       
Net Proceeds
    
54,676,761
    
22,338,445
    
145
%
  
124,595,639
    
69,821,734
    
78
%
                                       
Net Profits Percentage
    
80
%  
  
80
%  
        
80
%  
  
80
%  
      
                                       
Net Profits Income
  
$
43,741,409
  
$
17,870,756
    
145
%  
$
99,676,511
  
$
55,857,387
    
78
%

(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.

14

The following are explanations of significant variances on the underlying properties from third quarter 2007 to third quarter 2008 and from the first nine months of 2007 to the comparable period in 2008:

Sales Volumes

Gas

Gas sales volumes increased 2% for the third quarter and 3% for the nine-month period. Increased gas sales volumes are primarily because of increased production from new wells and workovers, partially offset by natural production decline.

Oil

Oil sales volumes increased 23% for the third quarter and 18% for the nine-month period primarily because of increased production from new wells and workovers, partially offset by natural production decline. In addition, oil sales volumes increased in the third quarter because of the timing of cash receipts, and increased for the nine-month period because of prior period volume adjustments in 2007.

Sales Prices

Gas

The third quarter 2008 average gas price was $10.15 per Mcf, a 71% increase from the third quarter 2007 average gas price of $5.93 per Mcf. For the nine-month period, the average gas price increased 38% to $8.29 per Mcf in 2008 from $6.02 per Mcf in 2007. Although the U.S. entered the winter with above average gas storage, a normal winter and lower liquefied natural gas imports led to normal storage levels. As a result of tighter storage levels and higher oil prices, gas prices reached as high as $13.00 per MMBtu. Due to concerns of oversupply from shale gas development, falling oil prices and a mild summer which led to increased gas in storage, recent gas prices have declined. Prices will continue to be affected by weather, oil prices, the U.S. economy, the level of North American production and import levels of liquified natural gas. Natural gas prices are expected to remain volatile. The third quarter 2008 gas price is primarily related to production from May through July 2008, when the average NYMEX price was $12.10 per MMBtu. The average NYMEX price for August and September 2008 was $8.81 per MMBtu. At October 15, 2008, the average NYMEX futures price for the following twelve months was $7.09 per MMBtu. Recent trust gas prices have averaged approximately 16% lower than the NYMEX price.

Scheduled pipeline maintenance on a major pipeline transporting gas from the Rocky Mountain region has led to lower realized gas prices in September 2008 for the trust’s Wyoming gas production. Realized gas prices for September 2008 Wyoming gas production are expected to be approximately 78% lower than the NYMEX price compared to recent prices which have averaged approximately 18% lower than the NYMEX price. The downward pressure on realized prices is expected to result in lower monthly trust distributions over the near term. At October 15, 2008, the average futures price for the following three months is expected to be approximately 33% lower than the NYMEX price. Wyoming gas production was approximately 27% of total trust gas production for the nine-month period ended September 30, 2008.

Oil

The third quarter 2008 average oil price was $125.74 per Bbl, a 93% increase from the third quarter 2007 average oil price of $65.14 per Bbl. The year-to-date average oil price increased 79% to $108.41 per Bbl in 2008 from $60.41 per Bbl in 2007. In the last few months of 2007 and the first half of 2008, continued tension in the Middle East, weakness in the U.S. dollar and strong demand caused prices to reach record levels of above $147.00 per Bbl. However, rising crude oil supplies, the tightened credit markets and the potential for lower demand in slowing U.S. and global economies have caused recent oil prices to decline. Oil prices are expected to remain volatile. The third quarter 2008 oil price is primarily related to production from May through July 2008, when the average NYMEX price was $131.56 per Bbl. The average NYMEX price for August and September 2008 was $110.57 per Bbl. At October 15, 2008, the average NYMEX futures price for the following twelve months was $76.66 per Bbl. Recent trust oil prices have averaged approximately 1% lower than the NYMEX price.

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Costs

Taxes, Transportation and Other

Taxes, transportation and other increased 55% for the quarter and 32% for the nine-month period primarily because of increased production taxes related to higher oil and gas revenues.

Production

Production expense increased 37% for the quarter and 21% for the nine-month period primarily because of increased maintenance, compressor rental, plugging and abandonment, fuel and labor costs. In addition, increased production expense for the nine-month period was partially offset by mechanical and marketing rebates.
 
Development

Development costs deducted in the calculation of net profits income are based on the development budget. These development costs increased 2% for the third quarter and 8% for the nine-month period primarily because of the timing of expenditures. During the first nine months of 2008, 28 wells were completed on the underlying properties and 10 wells were pending completion at September 30.

As of December 31, 2007, cumulative actual costs exceeded cumulative budgeted costs deducted by approximately $0.7 million. In calculating net profits income, XTO Energy deducted budgeted development costs of $11.5 million for the quarter and $34.0 million for the nine-month period. After considering actual development costs of $19.9 million for the quarter and $37.0 million for the nine-month period, actual costs exceeded cumulative budgeted costs by approximately $3.7 million at September 30, 2008.

XTO Energy has advised the trustee that total 2008 budgeted development costs for the underlying properties are approximately $46.0 million. The 2008 budget year generally coincides with the trust distribution months from April 2008 through March 2009. The monthly development cost deduction will be reevaluated by XTO Energy and revised as necessary, based on the 2008 budget and the timing and amount of actual expenditures. See Note 2 to Condensed Financial Statements.

Overhead

Overhead increased 12% for the quarter and 8% for the nine-month period primarily because of the annual rate adjustment based on an industry index.

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Excess Costs 

Costs exceeded revenues by $853,468 ($682,774 net to the trust) on properties underlying the Wyoming net profits interests in November and December 2007. Limited pipeline capacity for shipping from the Rocky Mountain region and excess regional supply led to significantly lower realized regional gas prices for production. These lower gas prices caused costs to exceed revenues on properties underlying the Wyoming net profits interests, however, these excess costs did not reduce net proceeds from the remaining conveyances.

XTO Energy advised the trustee that with the onset of winter demand and the completion of the first phase of a major pipeline expansion in January 2008, Rocky Mountain gas prices increased and the excess costs, plus accrued interest of $10,090 ($8,072 net to the trust), were fully recovered by February 2008.

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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, annual and monthly development, production and other costs and expenses, monthly development cost deductions, oil and gas prices and differentials to NYMEX prices, supply shortages, future drilling, workover and restimulation plans, future 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, 2007, 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, 2007.

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 timely alerting the trustee to material information relating to the trust required to be included in the trust’s periodic filings with the Securities and Exchange Commission. In its evaluation of disclosure controls and procedures, the trustee has relied, to the extent considered reasonable, on information provided by XTO Energy. 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, 2007.

Items 2 through 5.

Not applicable.

Item 6. Exhibits.

 
(a)
Exhibits.

Exhibit Number
and Description
   
(15)
Awareness letter of KPMG LLP
   
(31)
Rule 13a-14(a)/15d-14(a) Certification
   
(32)
Section 1350 Certification
   
(99)
Items 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 26, 2008 (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: October 29, 2008
By
/s/ Louis G. Baldwin
   
Louis G. Baldwin
   
Executive Vice President
   
and Chief Financial Officer
 
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