EXHIBIT 13

HUGOTON ROYALTY TRUST

GLOSSARY OF TERMS

The following are definitions of significant terms used in this Annual Report:

Bbl

Barrel (of oil)

Bcf

Billion cubic feet (of natural gas)

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.

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THE TRUST

Hugoton Royalty Trust was created on December 1, 1998 when XTO Energy Inc. conveyed 80% net profits interests in certain predominantly gas-producing properties located in Kansas, Oklahoma and Wyoming to the trust. The net profits interests are the only assets of the trust, other than cash held for trust expenses and for distribution to unitholders.

Net profits income received by the trust on the last business day of each month is calculated and paid by XTO Energy based on net proceeds received from the underlying properties in the prior month. Distributions, as calculated by the trustee, are paid to month-end unitholders of record within ten business days.

UNITS OF BENEFICIAL INTEREST

The units of beneficial interest in the trust began trading on the New York Stock Exchange on April 9, 1999 under the symbol “HGT.” The following are the high and low unit sales prices and total cash distributions per unit paid by the trust during each quarter of 2008 and 2007:

Sales Price

Distributions per Unit

Quarter

High

Low

2008

First

$29.85

$22.52

$0.544229

Second

37.86

27.14

0.838873

Third

37.65

24.50

1.092216

Fourth

27.29

14.00

0.437042

$2.912360


2007
First	$25.50	$22.61	$0.406057
Second	28.25	24.31	0.521150
Third	26.83	22.25	0.443367
Fourth	25.40	21.93	0.364139
			$1.734713

At December 31, 2008, there were 40,000,000 units outstanding and approximately 1,091 unitholders of record; 39,134,314 of these units were held by depository institutions.

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Forward-Looking Statements

This Annual Report, including the accompanying Form 10-K, 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 Annual Report and Form 10-K, including, without limitation, statements regarding estimates of proved reserves, future development plans and costs, and industry and market conditions, are forward-looking statements that are subject to a number of risks and uncertainties which are detailed in Part I, Item 1A of the accompanying Form 10-K. 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.

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SUMMARY

The trust was created to collect and distribute to unitholders monthly net profits income related to the 80% net profits interests. Such net profits income is calculated as 80% of the net proceeds received from certain working interests in predominantly gas-producing properties in Kansas, Oklahoma and Wyoming. Net proceeds from properties in each state are calculated by deducting production expense, development costs and overhead from revenues. If monthly costs exceed revenues from the underlying properties in any state, such excess costs must be recovered, with accrued interest, from future net proceeds of that state and cannot reduce net profits income from another state. Excess costs generally can occur during periods of higher development activity and/or lower gas prices.

Costs exceeded revenues on properties underlying the Wyoming net profits interests in November 2008 and November and December 2007. For further information on excess costs, see “Trustee’s Discussion and Analysis.”

•

Cost Depletion is generally available to unitholders as a deduction from royalty income. Available depletion is dependent upon the unitholder’s cost of units, purchase date and prior allowable depletion. It may be more beneficial for unitholders to deduct percentage depletion. Unitholders should consult their tax advisors for further information.

As an example, a unitholder that acquired units in January 2008 and held them throughout 2008 would be entitled to a cost depletion deduction of approximately 6% of his cost. Assuming a cost of $25.00 per unit, cost depletion would offset approximately 51% of 2008 taxable trust income. Assuming a 30% tax rate, the 2008 taxable equivalent return as a percentage of unit cost would be 14%. (NOTE — Because the units are a depleting asset, a portion of this return is effectively a return of capital.)

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TO UNITHOLDERS

We are pleased to present the 2008 Annual Report of the Hugoton Royalty Trust. This report includes a copy of the trust’s 2008 Form 10-K as filed with the Securities and Exchange Commission. Both reports contain important information about the trust’s net profits interests, including information provided to the trustee by XTO Energy, and should be read in conjunction with each other.

For the year ended December 31, 2008, net profits income totaled $117,268,069. After adding interest income of $91,203 and deducting trust administration expense of $864,872, distributable income was $116,494,400 or $2.912360 per unit. Net profits income and distributions were 66% and 68%, respectively, higher than 2007 amounts primarily because of higher oil and gas prices and increased oil production, partially offset by increased production expense, higher taxes, transportation and other costs and higher development costs.

Natural gas prices averaged $7.75 per Mcf for 2008, 36% higher than the 2007 average price of $5.70 per Mcf. The average 2008 oil price was $104.62 per Bbl, 63% higher than the 2007 average price of $64.35 per Bbl.

Gas sales volumes from the underlying properties for 2008 were 28,176,094 Mcf, or 76,984 Mcf per day, relatively flat compared to 76,965 Mcf per day in 2007. Oil sales volumes from the underlying properties were 341,754 Bbls, or 934 Bbls per day in 2008, an increase of 12% from 837 Bbls per day in 2007. For further information on sales volumes and product prices, see “Trustee’s Discussion and Analysis.”

As of December 31, 2008, proved reserves for the underlying properties were estimated by independent engineers to be 366.3 Bcf of natural gas and 3.3 million Bbls of oil. Natural gas reserves for the underlying properties declined 39.2 Bcf and oil reserves for the underlying properties declined approximately 336,000 Bbls primarily due to current year production and revisions due to lower year-end gas and oil prices, partially offset by additions from development activity. Based on an allocation of these reserves, proved reserves attributable to the net profits interests were estimated to be 178.5 Bcf of natural gas and 1.7 million Bbls of oil. Estimated gas and oil reserves attributable to the net profits interests declined from previously reported reserves at year-end 2007, as current year production and revisions due to lower year-end prices were only partially offset by additions from development activities. All reserve information prepared by independent engineers has been provided to the trustee by XTO Energy.

Estimated future net cash flows from proved reserves of the net profits interests at December 31, 2008 are $807 million. Using an annual discount factor of 10%, the present value of estimated future net cash flows at December 31, 2008 is $412 million. Proved reserve estimates and related future net cash flows have been determined based on a year-end average realized gas price of $4.47 per Mcf and a year-end West Texas Intermediate posted oil price of $41.22 per Bbl. Other guidelines used in estimating proved reserves, as prescribed by the Financial Accounting Standards Board, are described under Item 2 of the accompanying Form 10-K. The present value of estimated future net cash flows is computed based on SEC guidelines and is not necessarily representative of the market value of trust units.

As disclosed in the tax instructions provided to unitholders in February 2009, trust distributions are considered portfolio income, rather than passive income. Unitholders should consult their tax advisors for further information.

Hugoton Royalty Trust
By: U.S. Trust, Bank of America
Private Wealth Management, Trustee

By: Nancy G. Willis
Vice President

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THE UNDERLYING PROPERTIES

The underlying properties are predominantly gas-producing properties with established production histories in the Hugoton area of Oklahoma and Kansas, the Anadarko Basin of Oklahoma and the Green River Basin of Wyoming. The average reserve-to-production index for the underlying properties as of December 31, 2008 is approximately 13 years. This index is calculated using total proved reserves and estimated 2009 production for the underlying properties. The projected 2009 production is from proved developed producing reserves as of December 31, 2008. Based on estimated future net cash flows at year-end oil and gas prices, the proved reserves of the underlying properties are approximately 92% natural gas and 8% oil. XTO Energy operates approximately 94% of the underlying properties.

Because the underlying properties are working interests, production expense, development costs and overhead are deducted in calculating net profits income. As a result, net profits income is affected by the level of maintenance and development activity on the underlying properties. See “Trustee’s Discussion and Analysis — Years Ended December 31, 2008, 2007 and 2006 — Costs.” Total 2008 development costs deducted for the underlying properties were $46 million, an increase of 8% from the prior year. XTO Energy has informed the trustee that total 2009 budgeted development costs for the underlying properties are approximately $33 million.

Hugoton Area

Discovered in 1922, the Hugoton area is one of the largest natural gas producing areas in the United States. During 2008, gas sales volumes from the underlying properties in the Hugoton area were 7.6 Bcf, or approximately 27% of total sales volumes from the underlying properties. Most of the production is from the Chase formation. XTO Energy has informed the trustee that it plans to develop other formations, including the Council Grove, Chester, Morrow and St. Louis formations that underlie the 79,500 net acres held by production by the Chase formation wells.

Within this area, XTO Energy performed 13 workovers in 2008, of which 2 were Chase restimulations. XTO Energy has informed the trustee that it does not plan to drill any new wells and will perform up to 16 workovers in this area during 2009.

Anadarko Basin

The Anadarko Basin of western Oklahoma was discovered in 1945. Gas sales volumes from the underlying properties in the Anadarko Basin totaled 13.0 Bcf in 2008, or approximately 46% of total sales volumes from the underlying properties. XTO Energy is one of the largest producers in the Ringwood, Northwest Okeene and Cheyenne Valley fields of Major County, the Northeast Cedardale field of Woodward County and the Elk City field of Beckham County, the principal producing regions of the underlying properties in the Anadarko Basin.

In Major County, XTO Energy drilled 16 gross (10.6 net) wells and performed 28 workovers in 2008. XTO Energy has informed the trustee that it plans to drill up to 8 wells and perform up to 10 workovers in Major County during 2009. In Woodward County, XTO Energy drilled 11 gross (8.7 net) wells and performed 5 workovers in 2008. XTO Energy has informed the trustee that it plans to drill up to 8 wells and perform up to 4 workovers in Woodward County during 2009.

In the Elk City field, XTO Energy drilled 1 gross (0.9 net) wells and performed 7 workovers in 2008. XTO Energy has informed the trustee that it does not plan to drill any new wells and will perform 3 workovers within the Elk City field during 2009.

Green River Basin

The Green River Basin is located in southwestern Wyoming. Natural gas was discovered in the Fontenelle Field of the Green River Basin in the early 1970s. The producing reservoirs are the Frontier, Baxter and Dakota sandstones. Gas sales volumes from the underlying properties in the Green River Basin were 7.6 Bcf in 2008, or approximately 27% of total sales volumes from the underlying properties.

In 2008, XTO Energy completed 7 gross (7.0 net) wells and performed 9 workovers. XTO Energy has informed the trustee that it does not plan to drill any new wells and will perform up to 6 workovers in the

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Green River Basin during 2009. XTO Energy has informed the trustee that it is continuing its efforts to reduce pipeline pressure which has shown potential for increasing production and extending field life in the Fontenelle Field.

Estimated Proved Reserves and Future Net Cash Flows

The following are proved reserves of the underlying properties, as estimated by independent engineers, and proved reserves and future net cash flows from proved reserves of the net profits interests, based on an allocation of these reserves, at December 31, 2008:


	Underlying Properties				Net Profits Interests
	Proved Reserves^(a)				Proved Reserves^(a)(b)				Future Net Cash Flows from Proved Reserves^(a)(c)
	Gas (Mcf)		Oil (Bbls)		Gas (Mcf)		Oil (Bbls)		Undiscounted		Discounted
(in Thousands)
Oklahoma		240,591		3,126		123,040		1,600	$	598,138	$	302,085
Wyoming		100,832		110		44,040		48		168,079		86,264
Kansas		24,882		73		11,403		34		41,116		23,451
TOTAL		366,305		3,309		178,483		1,682	$	807,333	$	411,800

(a)

Based on year-end oil and gas prices. For further information regarding trust proved reserves, see Item 2 of the accompanying Form 10-K.

(b)

Since the trust has defined net profits interests, the trust does not own a specific percentage of the oil and gas reserves. Because trust reserve quantities are determined using an allocation formula, any fluctuations in actual or assumed prices or costs will result in revisions to the estimated reserve quantities allocated to the net profits interests.

(c)

Before income taxes since future net cash flows are not subject to taxation at the trust level.

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TRUSTEE’S DISCUSSION AND ANALYSIS

Years Ended December 31, 2008, 2007 and 2006

Net profits income for 2008 was $117,268,069, as compared with $70,499,584 for 2007 and $91,241,196 for 2006. The 66% increase in net profits income from 2007 to 2008 is primarily the result of higher oil and gas prices and increased oil production, partially offset by increased production expense, higher taxes, transportation and other costs and higher development costs. The 23% decrease in net profits income from 2006 to 2007 was primarily the result of lower gas sales volumes and gas prices, partially offset by lower development costs. Approximately 85% in 2008, 88% in 2007 and 91% in 2006 of net profits income was derived from natural gas sales.

Trust administration expense was $864,872 in 2008 as compared to $1,246,189 in 2007 and $528,978 in 2006. Administration expense decreased 31% from 2007 to 2008 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. Administration expense increased significantly from 2006 to 2007 primarily because of additional unitholder tax reporting, an increased number of unitholders and the timing of expenditures. Interest income was $91,203 in 2008, $135,125 in 2007 and $198,542 in 2006. Changes in interest income are attributable to fluctuations in net profits income and interest rates. Distributable income was $116,494,400 or $2.912360 per unit in 2008, $69,388,520 or $1.734713 per unit in 2007 and $90,910,760 or $2.272769 per unit in 2006.

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.

Volumes

From 2007 to 2008, underlying gas sales volumes remained flat as increased production from new wells and workovers was offset by natural production decline. Underlying oil sales volumes increased 12% from 2007 to 2008 primarily because of increased production from new wells and workovers and prior period volume adjustments in 2007, partially offset by natural production decline. From 2006 to 2007, underlying gas sales volumes decreased 5% and underlying oil sales volumes decreased 8%. Lower gas and oil sales volumes were primarily because of natural production decline, partially offset by increased production from new wells and workovers and the timing of cash receipts. In addition, oil sales volumes were lower because of the effects of prior period volume adjustments in 2007.

Prices

Gas. The 2008 average gas price was $7.75 per Mcf, a 36% increase from the 2007 average gas price of $5.70 Mcf, which was 14% lower than the 2006 average gas price of $6.59 per Mcf. Beginning in 2006 and into 2007, gas prices trended lower primarily because of an adequate natural gas supply inventory due to the warmer than normal winter weather in 2006 and the absence of hurricane activity in the Gulf of Mexico. Much colder temperatures in early 2007 caused prices to partially rebound. As a result of tighter storage levels and higher oil prices, gas prices increased in the first half of 2008 and reached as high as $13.00 per MMBtu in July. Due to concerns of oversupply from shale gas development, declining demand due to the deepening U.S. recession, falling oil prices and increased gas storage, recent gas prices have declined. Natural gas prices are expected to remain volatile.

Gas prices in the Rocky Mountain region were significantly lower for September through November 2008 and April through November 2007 production primarily as a result of scheduled pipeline maintenance in 2008, as well as, pipeline constraints and limited regional demand. This resulted in lower realized prices for the trust’s Wyoming gas production for the November 2008 through January 2009 and June 2007 through January 2008 distributions which, in turn, resulted in excess costs on properties underlying the Wyoming net profits interests (see “Excess costs” below). The onset of winter demand and the completion of scheduled

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pipeline maintenance have led to a partial rebound of Rocky Mountain gas prices. At February 18, 2009, the average futures price for Wyoming gas for the following six months is expected to be approximately 31% lower than the NYMEX price. Wyoming gas production was approximately 27% of total trust gas production for the year ended December 31, 2008.

The trust’s average realized gas price was $7.75 per Mcf, 15% lower than the average NYMEX price of $9.13 in 2008; $5.70 per Mcf, 18% lower than the average NYMEX price of $6.94 in 2007; and $6.59 per Mcf, or 18%, lower than the average NYMEX price of $8.02 in 2006. The average NYMEX price for November 2008 through January 2009 was $6.50 per MMBtu. At February 18, 2009, the average NYMEX gas price for the following 12 months was $4.97 per MMBtu. Recent trust gas prices have averaged approximately 44% lower than the NYMEX price.

Oil. The average oil price for 2008 was $104.62 per Bbl, 63% higher than the average oil price for 2007 of $64.35 per Bbl, which was 1% higher than the average oil price for 2006 of $63.73 per Bbl. Oil prices have risen primarily because of increasing global demand and supply shortage concerns, inadequate sour crude refining capacity, reduced production as a result of tropical storms and political instability in some oil producing countries. In the last few months of 2007 and the first half of 2008, narrowing excess worldwide capacity, weakness in the dollar and continuing tension in the Middle East caused prices to reach record levels above $147.00 per Bbl in July 2008. However, lower demand as a result of the deepening U.S. recession and slowing global economy, the tightened credit markets and rising crude oil supplies have caused oil prices to decline sharply in the second half of 2008. Oil prices are expected to remain volatile. The average NYMEX price for November 2008 through January 2009 was $46.91 per Bbl. At February 18, 2009, the average NYMEX oil price for the following 12 months was $42.98 per Bbl. Recent trust oil prices have averaged approximately 4% lower than the NYMEX price.

Costs

The calculation of net profits income includes deductions for production expense, development costs and overhead since the related underlying properties are working interests. If monthly costs exceed revenues for any state, these excess costs must be recovered, with accrued interest, from future net proceeds of that state and cannot reduce net profits income from another state. See “Excess costs” below.

Taxes, Transportation and Other. Taxes, transportation and other generally fluctuates with changes in total revenues. Taxes, transportation and other increased 26% from 2007 to 2008 primarily because of increased production taxes related to higher revenues, partially offset by decreased property taxes. Taxes, transportation and other decreased 8% from 2006 to 2007 primarily because of decreased production taxes related to lower revenues, partially offset by increased purchaser deductions.

Production. Production expense increased 23% from 2007 to 2008 primarily because of overall price increases as well as increased location, repairs and maintenance, fuel, compressor rentals and labor costs, partially offset by mechanical and marketing rebates. Production expense was relatively unchanged from 2006 to 2007 as increased labor and compressor rental costs were largely offset by decreased fuel costs.

Development. Development costs deducted were $46.0 million in 2008, $42.8 million in 2007 and $51.7 million in 2006. In 2008, actual development costs were $52.6 million. At December 31, 2008, cumulative actual costs exceeded cumulative budgeted costs by approximately $7.3 million. 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 was maintained at that level for the remainder of 2008. XTO Energy has advised the trustee that this monthly deduction will continue to be evaluated and revised as necessary.

Overhead. Overhead is charged by XTO Energy for administrative expenses incurred to support operations of the underlying properties. Overhead fluctuates based on changes in the active well count and drilling activity on the underlying properties, as well as an annual cost level adjustment.

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Excess Costs. Costs exceeded revenues by $970,780 ($776,624 net to the trust) on properties underlying the Wyoming net profits interests in November 2008. Scheduled pipeline maintenance and limited regional demand led to lower realized gas prices for production in the Rocky Mountain region (see “Prices” above). These lower gas prices caused costs to exceed revenues on properties underlying the Wyoming net profits interest, however, these excess costs did not reduce net proceeds from the remaining conveyances. XTO Energy has advised the trustee that the onset of winter demand and completion of scheduled pipeline maintenance led to a partial rebound of Rocky Mountain gas prices, resulting in the full recovery of excess costs plus accrued interest of $3,192 ($2,554 net to the trust) in December 2008.

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 and moderate regional demand led to lower realized gas prices for production in the Rocky Mountain region (see “Prices” above). These lower gas prices caused costs to exceed revenues on properties underlying the Wyoming net profits interest, however, these excess costs did not reduce net proceeds from the remaining conveyances. XTO Energy advised the trustee that with 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), was fully recovered by February 2008.

Fourth Quarter 2008 and 2007

During fourth quarter 2008 the trust received net profits income totaling $17,591,558 compared with fourth quarter 2007 net profits income of $14,642,197. This 20% increase in net profits income was primarily due to increased oil and gas prices, partially offset by decreased oil and gas volumes and increased production expense.

Administration expense was $127,280 and interest income was $17,402, resulting in fourth quarter 2008 distributable income of $17,481,680, or $0.437042 per unit. Distributable income for fourth quarter 2007 was $14,565,560 or $0.364139 per unit. Distributions to unitholders for the quarter ended December 31, 2008 were:


Record Date	Payment Date		Per Unit
October 31, 2008		November 17, 2008		$0.274018
November 28, 2008		December 12, 2008		0.134378
December 31, 2008		January 15, 2009		0.028646
				$0.437042

Volumes

Fourth quarter underlying gas sales volumes decreased 6% and underlying oil sales volumes decreased 5% from 2007 to 2008. Gas and oil sales volumes decreased primarily because of natural production decline and the timing of cash receipts, partially offset by increased production from new wells and workovers.

Prices

The average fourth quarter 2008 gas price was $6.03 per Mcf, or 26% higher than the fourth quarter 2007 average price of $4.77 per Mcf. The average fourth quarter 2008 oil price was $91.81 per Bbl, or 22% higher than the fourth quarter 2007 average price of $75.10 per Bbl. For further information about product prices, see “Years Ended December 31, 2008, 2007 and 2006 — Prices” above.

Costs

Taxes, Transportation and Other. Taxes, transportation and other generally fluctuates with changes in total revenues. Taxes, transportation and other increased 7% from 2007 to 2008 primarily due to the 18% increase in total revenues over the same period, partially offset by decreased property taxes.

Production. Fourth quarter production expense increased 30% from 2007 to 2008 primarily because of overall price increases as well as increased compressor rentals, location, maintenance and fuel costs.

Development. Development costs, which were deducted based on budgeted development costs, increased 7% from fourth quarter 2007 to 2008 primarily because of the timing of expenditures.

Overhead. Overhead increased 10% from fourth quarter 2007 to 2008 primarily because of the annual rate adjustment based on an oil and gas industry index.

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Excess Costs. Costs exceeded revenues by $970,780 ($776,624 net to the trust) on properties underlying the Wyoming net profits interests in November 2008. Scheduled pipeline maintenance and limited regional demand led to lower realized gas prices for production in the Rocky Mountain region (see “Years Ended December 31, 2008, 2007 and 2006 — Prices” above). 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 has advised the trustee that the onset of winter demand and the completion of scheduled pipeline maintenance led to a partial rebound of Rocky Mountain gas prices, resulting in the full recovery of excess costs plus accrued interest of $3,192 ($2,554 net to the trust) in December 2008.

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 and moderate regional demand led to lower realized gas prices for production in the Rocky Mountain region (see “Prices” above). These lower gas prices caused costs to exceed revenues on properties underlying the Wyoming net profits interest, 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), was fully recovered by February 2008.

For further information about costs, see “Years Ended December 31, 2008, 2007 and 2006 — Costs” above.

See Item 7 of the accompanying Form 10-K for disclosures regarding liquidity and capital resources, off-balance sheet arrangements, contractual obligations and commitments, related party transactions and critical accounting policies of the trust. See Item 7A of the accompanying Form 10-K for quantitative and qualitative disclosures about market risk affecting the trust.

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Calculation of Net Profits Income

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


	Year Ended December 31^(a)								Three Months Ended December 31^(a)
	2008		2007			2006			2008		2007
Sales Volumes
Gas (Mcf)^(b)
Underlying properties		28,176,094		28,092,224			29,628,079			6,808,017		7,253,325
Average per day		76,984		76,965			81,173			74,000		78,840
Net profits interests		13,134,564		11,233,503			12,871,453			2,218,747		2,413,294
Oil (Bbls)^(b)
Underlying properties		341,754		305,594			332,525			77,975		82,039
Average per day		934		837			911			848		892
Net profits interests		169,915		140,805			145,230			29,676		34,495
Average Sales Prices
Gas (per Mcf)		$ 7.75		$ 5.70			$ 6.59			$ 6.03		$ 4.77
Oil (per Bbl)		$ 104.62		$ 64.35			$ 63.73			$ 91.81		$ 75.10
Revenues
Gas sales		$218,253,910		$160,104,931			$195,130,332			$41,058,215		$34,589,223
Oil sales		35,754,556		19,666,471			21,190,530			7,158,846		6,160,932
Total Revenues		254,008,466		179,771,402			216,320,862			48,217,061		40,750,155
Costs
Taxes, transportation and other		23,271,226		18,429,983			20,074,451			4,643,403		4,333,853
Production expense		27,454,543		22,268,104			22,231,559			7,028,920		5,391,813
Development costs^(c)		46,000,000		42,750,000			51,700,000			12,000,000		11,250,000
Overhead		9,830,861		9,052,303			8,263,357			2,552,099		2,325,211
Excess costs^(d)		866,750		(853,468	)		—			3,192		(853,468	)
Total Costs		107,423,380		91,646,922			102,269,367			26,227,614		22,447,409
Net Proceeds		146,585,086		88,124,480			114,051,495			21,989,447		18,302,746
Net Profits Percentage		80%		80	%		80	%		80%		80	%
Net Profits Income		$117,268,069		$70,499,584			$91,241,196			$17,591,558		$14,642,197

(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 year ended December 31 generally relate to twelve months of production for the period November through October, and 2) oil and gas sales for the three months ended December 31 generally relate to production for the period August through October.

(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 5 to Financial Statements.

(d)

See Note 4 to Financial Statements.

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HUGOTON ROYALTY TRUST

STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS


	December 31
	2008		2007
Assets
Cash and short-term investments		$1,145,840		$5,214,000
Net profits interests in oil and gas properties – net (Notes 1 and 2)		146,722,015		155,820,033
		$147,867,855		$161,034,033
Liabilities and Trust Corpus
Distribution payable to unitholders		$1,145,840		$5,214,000
Trust corpus (40,000,000 units of beneficial interest authorized and outstanding)		146,722,015		155,820,033
		$147,867,855		$161,034,033

STATEMENTS OF DISTRIBUTABLE INCOME


	Year Ended December 31
	2008		2007		2006
Net profits income		$117,268,069		$70,499,584		$91,241,196
Interest income		91,203		135,125		198,542
Total income		117,359,272		70,634,709		91,439,738
Administration expense		864,872		1,246,189		528,978
Distributable income		$116,494,400		$69,388,520		$90,910,760
Distributable income per unit (40,000,000 units)		$2.912360		$1.734713		$2.272769

STATEMENTS OF CHANGES IN TRUST CORPUS


	Year Ended December 31
	2008		2007		2006

Trust corpus, beginning of year		$155,820,033		$163,796,772		$171,935,330
Amortization of net profits interests		(9,098,018)		(7,976,739)		(8,138,558)
Distributable income		116,494,400		69,388,520		90,910,760
Distributions declared		(116,494,400)		(69,388,520)		(90,910,760)
Trust corpus, end of year		$146,722,015		$155,820,033		$163,796,772

See Accompanying Notes to Financial Statements.

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HUGOTON ROYALTY TRUST

NOTES TO FINANCIAL STATEMENTS

1. Trust Organization and Provisions

Hugoton Royalty Trust was created on December 1, 1998 by XTO Energy Inc. (formerly known as “Cross Timbers Oil Company”). Effective on that date, XTO Energy conveyed 80% net profits interests in certain predominantly gas-producing working interest properties in Kansas, Oklahoma and Wyoming to the trust under separate conveyances for each of the three states. In exchange for the conveyances of the net profits interests to the trust, XTO Energy received 40 million units of beneficial interest in the trust. The trust’s initial public offering was in April 1999. The majority of the underlying working interest properties are currently owned and operated by XTO Energy (Note 7).

Bank of America, N.A. is the trustee for the trust. In 2007 the Bank of America private wealth management group officially became known as “U.S. Trust, Bank of America Private Wealth Management.” The legal entity that serves as the trustee of the trust did not change, and references in this Annual Report to U.S. Trust, Bank of America Private Wealth Management shall describe the legal entity Bank of America, N.A. The trust indenture provides, among other provisions, that:

•

the trust cannot engage in any business activity or acquire any assets other than the net profits interests and specific short-term cash investments;

•

the trust may dispose of all or part of the net profits interests if approved by 80% of the unitholders, or upon trust termination. Otherwise, the trust may sell up to 1% of the value of the net profits interests in any calendar year, pursuant to notice from XTO Energy of its desire to sell the related underlying properties. Any sale must be for cash with the proceeds promptly distributed to the unitholders;

•

the trustee may establish a cash reserve for payment of any liability that is contingent or not currently payable;

•

the trustee may borrow funds to pay trust liabilities if repaid in full prior to further distributions to unitholders;

•

the trustee will make monthly cash distributions to unitholders (Note 3); and

•

the trust will terminate upon the first occurrence of:

—

disposition of all net profits interests pursuant to terms of the trust indenture,

—

gross proceeds from the underlying properties falling below $1 million per year for two successive years, or

—

a vote of 80% of the unitholders to terminate the trust in accordance with provisions of the trust indenture.

2. Basis of Accounting

The financial statements of the 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:

•

Net profits income is recorded in the month received by the trustee (Note 3).

•

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 (Note 3).

The most significant differences between the trust’s financial statements and those prepared in accordance with U.S. generally accepted accounting principles are:

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HUGOTON ROYALTY TRUST

NOTES TO FINANCIAL STATEMENTS

2. Basis of Accounting – (continued)

•

Net profits income is recognized in the month received rather than accrued in the month of production.

•

Expenses are recognized when paid rather than when incurred.

•

Cash reserves may be established by the trustee for contingencies that would not be recorded under U.S. generally accepted accounting principles.

This comprehensive basis of accounting 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. generally accepted accounting principles, 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.

In December 2008, the Securities and Exchange Commission (SEC) released Final Rule,Modernization of Oil and Gas Reporting.The new disclosure requirements include provisions that permit the use of new technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserves volumes. The new requirements also will allow companies to disclose their probable and possible reserves to investors. In addition, the new disclosure requirements require companies to: (a) report the independence and qualifications of its reserves preparer or auditor; (b) file reports when a third party is relied upon to prepare reserves estimates or conducts a reserves audit; and (c) report oil and gas reserves using an average price based upon the prior 12-month period rather than year-end prices. The new disclosure requirements are effective for financial statements for fiscal years ending on or after December 31, 2009. The effect of adopting the SEC rule has not been determined, but it is not expected to have a significant effect on our reported financial position or distributable income.

The initial carrying value of the net profits interests of $247,066,951 was XTO Energy’s historical net book value of 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 $100,344,936 as of December 31, 2008 and $91,246,918 as of December 31, 2007.

3. Distributions to Unitholders

The trustee determines the amount to be distributed to unitholders each month by totaling net profits income, interest income and other cash receipts, and subtracting liabilities paid and adjustments in cash reserves established by the trustee. The resulting amount is distributed to unitholders of record within ten business days after the monthly record date, which is the last business day of the month.

Net profits income received by the trustee consists of net proceeds received in the prior month by XTO Energy from the underlying properties, multiplied by 80%. Net proceeds are the gross proceeds received from the sale of production, less costs. Costs generally include applicable taxes, transportation, legal and marketing charges, production expense, development and drilling costs, and overhead (Note 7).

XTO Energy, as owner of the underlying properties, computes net profits income separately for each of the three conveyances (one for each of the states of Kansas, Oklahoma and Wyoming). If 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 profits income from the other conveyances (Note 4).

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HUGOTON ROYALTY TRUST

NOTES TO FINANCIAL STATEMENTS

4. Excess Costs

Costs exceeded revenues by $970,780 ($776,624 net to the trust) on properties underlying the Wyoming net profits interests in November 2008. Scheduled pipeline maintenance and limited regional demand led to lower realized gas prices for production in the Rocky Mountain region. These lower gas prices caused costs to exceed revenues on properties underlying the Wyoming net profits interest, however, these excess costs did not reduce net proceeds from the remaining conveyances. XTO Energy has advised the trustee that the onset of winter demand and completion of scheduled pipeline maintenance led to a partial rebound of Rocky Mountain gas prices, resulting in the full recovery of excess costs plus accrued interest of $3,192 ($2,554 net to the trust) in December 2008.

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 and moderate regional demand led to lower realized gas prices for production in the Rocky Mountain region (see “Prices” above). These lower gas prices caused costs to exceed revenues on properties underlying the Wyoming net profits interest, 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), was fully recovered by February 2008.

5. 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:


	Year Ended December 31
	2008		2007		2006
Cumulative actual costs (over) under the amount deducted – beginning of period		$(675,754)		$(3,410,174)		$113,905
Actual costs		(52,638,330)		(40,015,580)		(55,224,079)
Budgeted costs deducted		46,000,000		42,750,000		51,700,000
Cumulative actual costs (over) under the amount deducted – end of period		$(7,314,084)		$(675,754)		$(3,410,174)

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 was maintained at that level for the remainder of 2008. XTO Energy has advised the trustee that this monthly deduction will continue to be evaluated and revised as necessary.

6. Federal Income Taxes

Tax counsel has advised the trust that, under current tax laws, the trust will be classified as a grantor trust for federal income tax purposes and, therefore, is not subject to taxation at the trust level. However, the opinion of tax counsel is not binding on the Internal Revenue Service.

For federal income tax purposes, unitholders of a grantor trust 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 be received or accrued by the unitholders at the time such income is received or accrued by the trust, rather than when distributed by the trust.

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NOTES TO FINANCIAL STATEMENTS

6. Federal Income Taxes – (continued)

The trust is a widely held fixed investment trust (“WHFIT”) classified as a non-mortgage widely held fixed investment trust (“NMWHFIT”) for federal income tax purposes. The trustee is the representative of the trust that will provide tax information in accordance with the applicable U.S. Treasury Regulations governing the information reporting requirements of the trust as a WHFIT or a NMWHFIT.

7. XTO Energy Inc.

XTO Energy operates approximately 94% of the underlying properties. In computing net proceeds, XTO Energy deducts an overhead charge for reimbursement of administrative expenses on the underlying properties it operates. As of December 31, 2008, the overhead charge was approximately $850,000 ($680,000 net to the trust) per month and is subject to annual adjustment based on an oil and gas industry index as defined in the trust agreement.

In April and May 1999, XTO Energy sold 17 million trust units in the trust’s initial public offering, and later in 1999 and 2000, sold 1.3 million trust units to certain of its officers. The trust did not receive the proceeds from these sales of trust units. In May 2006, XTO Energy distributed all of its remaining 21.7 million trust units as a dividend to its common stockholders. XTO Energy currently is not a unitholder of the trust.

XTO Energy sells a significant portion of natural gas production from the underlying properties to certain of XTO Energy’s wholly owned subsidiaries under contracts in existence when the trust was created, generally at amounts approximating monthly published market prices. Most of the production from the Hugoton area is sold under a contract to Timberland Gathering & Processing Company, Inc. (“TGPC”) based on the index price. Much of the gas production in Major County, Oklahoma is sold to Ringwood Gathering Company (“RGC”), which retains approximately $0.31 per Mcf as a compression and gathering fee. TGPC and RGC sell gas to Cross Timbers Energy Services, Inc. (“CTES”), which markets gas to third parties. XTO Energy sells directly to CTES most gas production not sold directly to TGPC or RGC.

Total gas sales from the underlying properties to XTO Energy’s wholly owned subsidiaries were $103.3 million for 2008, or 47% of total gas sales, $76.6 million for 2007, or 48% of total gas sales and $103.2 million for 2006, or 53% of total gas sales.

8. Contingencies

Litigation

On October 17, 1997, an action, styledUnited 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 thequi 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

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HUGOTON ROYALTY TRUST

NOTES TO FINANCIAL STATEMENTS

8. Contingencies – (continued)

believes that the allegations of this lawsuit are without merit and intends to vigorously defend the action. However, an order to change measuring practices or a related settlement could adversely affect the trust by reducing net proceeds in the future by an amount that is presently not determinable, but, in XTO Energy management’s opinion, is not currently expected to be material to the trust’s annual distributable income, financial position or liquidity.

An amended petition for a class action lawsuit,Beer, et al. v. XTO Energy Inc., was filed in January 2006, in the District Court of Texas County, Oklahoma by royalty owners of natural gas wells in Oklahoma. The plaintiffs allege that XTO Energy has not properly accounted to the plaintiffs for the royalties to which they are entitled and seek an accounting regarding the natural gas and other products produced from their wells and the prices paid for the natural gas and other products produced, and for payment of the monies allegedly owed since June 2002, with a certain limited number of plaintiffs claiming monies owed for additional time. XTO Energy removed the case to federal district court in Oklahoma City. A hearing on the class certification was conducted in October 2008. No decision has been made. 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.

In September 2008, a class action lawsuit was filed against XTO Energy styledWallace 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 plaintiff’s claims overlap the claims made by the plaintiffs in theBeer case as to certain properties. XTO Energy has answered and denied all claims. 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.

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,

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HUGOTON ROYALTY TRUST

NOTES TO FINANCIAL STATEMENTS

8. Contingencies – (continued)

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.

9. Supplemental Oil and Gas Reserve Information (Unaudited)

Proved oil and gas reserve information is included in Item 2 of the trust’s Annual Report on Form 10-K included in this report.

10. Quarterly Financial Data (Unaudited)

The following is a summary of net profits income, distributable income and distributable income per unit by quarter for 2008 and 2007:

Net Profits Income

Distributable Income

Distributable Income per Unit

2008

First Quarter

$22,035,854

$21,769,160

$0.544229

Second Quarter

33,899,248

33,554,920

0.838873

Third Quarter

43,741,409

43,688,640

1.092216

Fourth Quarter

17,591,558

17,481,680

0.437042

$117,268,069

$116,494,400

$2.912360

2007

First Quarter

$16,735,385

$16,242,280

$0.406057

Second Quarter

21,251,246

20,846,000

0.521150

Third Quarter

17,870,756

17,734,680

0.443367

Fourth Quarter

14,642,197

14,565,560

0.364139

$70,499,584

$69,388,520

$1.734713

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Bank of America, N.A., as Trustee for the Hugoton Royalty Trust:

We have audited the accompanying statements of assets, liabilities, and trust corpus of the Hugoton Royalty Trust as of December 31, 2008 and 2007 and related statements of distributable income and changes in trust corpus for each of the years in the three-year period ended December 31, 2008. We also have audited Hugoton Royalty Trust’s internal control over financial reporting as of December 31, 2008, based on criteria established inInternal Control — Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The trustee of Hugoton Royalty Trust is responsible for these financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on these financial statements and an opinion on the trust’s internal control over financial reporting based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by the trustee, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

As described in note 2 to the financial statements, these financial statements were prepared on the modified cash basis of accounting, which is a comprehensive basis of accounting other than accounting principles generally accepted in the United States of America.

The trust’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with the modified cash basis of accounting. The trust’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the trust; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with the modified cash basis of accounting, and that receipts and expenditures of the trust are being made only in accordance with authorizations of the trustee; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the trust’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the financial statements referred to above present fairly, in all material respects, the assets, liabilities, and trust corpus of Hugoton Royalty Trust as of December 31, 2008 and 2007, and its distributable income and changes in trust corpus for each of the years in the three-year period ended December 31, 2008, in conformity with the modified cash basis of accounting described in note 2. Also in our opinion, Hugoton Royalty Trust maintained, in all material respects, effective internal control over financial reporting as of December 31, 2008, based on control criteria established inInternal Control — Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission.

KPMG LLP

Fort Worth, Texas
February 25, 2009

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