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
   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 2007 and 2006:



Sales Price

          

          Distributions per UnitQuarter

          

          High

          

          Low2007First

          

          

          $ 25.50

          

          

          $

          22.61

          

          

          $

          0.406057Second

          

          

          28.25

          

          

          

          24.31

          

          

          

          0.521150Third

          

          

          26.83

          

          

          

          22.25

          

          

          

          0.443367Fourth

          

          

          25.40

          

          

          

          21.93

          

          

          

          0.364139$ 1.7347132006First

          

          $

          39.00

          

          

          $

          29.27

          

          

          $

          0.976040Second

          

          

          32.20

          

          

          

          25.05

          

          

          

          0.524306Third

          

          

          31.85

          

          

          

          24.30

          

          

          

          0.423020Fourth

          

          

          28.20

          

          

          

          24.15

          

          

          

          0.349403$

          2.272769

At December 31, 2007, there were 40,000,000 units outstanding and approximately 1,144 unitholders of record; 39,119,845 of these units were held by depository institutions. 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.

1

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.

2

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 lower gas prices.

Costs exceeded revenues on properties underlying the Wyoming net profits interests in 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 2007 and held them throughout 2007 would be entitled to a cost depletion deduction of approximately 5% of his cost. Assuming a cost of $24.00 per unit, cost depletion would offset approximately 69% of 2007 taxable trust income. Assuming a 30% tax rate, the 2007 taxable equivalent return as a percentage of unit cost would be 9%. (NOTE  Because the units are a depleting asset, a portion of this return is effectively a return of capital.)

3

TO UNITHOLDERS

We are pleased to present the 2007 Annual Report of the Hugoton Royalty Trust. This report includes a copy of the trusts 2007 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, 2007, net profits income totaled $70,499,584. After adding interest income of $135,125 and deducting trust administration expense of $1,246,189, distributable income was $69,388,520 or $1.734713 per unit. Net profits income and distributions were 23% and 24%, respectively, lower than 2006 amounts primarily because of lower gas sales volumes and gas prices, partially offset by lower development costs on the underlying properties.

Natural gas prices averaged $5.70 per Mcf for 2007, 14% lower than the 2006 average price of $6.59 per Mcf. The average 2007 oil price was $64.35 per Bbl, 1% higher than the 2006 average price of $63.73 per Bbl.

Gas sales volumes from the underlying properties for 2007 were 28,092,224 Mcf, or 76,965 Mcf per day, or a 5% decline from 81,173 Mcf per day in 2006. Oil sales volumes from the underlying properties were 305,594 Bbls, or 837 Bbls per day in 2007, or a decrease of 8% from 911 Bbls per day in 2006. For further information on sales volumes and product prices, see Trustees Discussion and Analysis.

As of December 31, 2007, proved reserves for the underlying properties were estimated by independent engineers to be 405.5 Bcf of natural gas and 3.6 million Bbls of oil. Natural gas reserves for the underlying properties declined 15.0 Bcf and oil reserves for the underlying properties declined approximately 200,000 Bbls primarily due to current year production, 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 224.9 Bcf of natural gas and 2.1 million Bbls of oil. Estimated gas and oil reserves attributable to the net
profits interests declined from previously reported reserves at year-end 2006, as current year production was 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, 2007 are $1.6 billion. Using an annual discount factor of 10%, the present value of estimated future net cash flows at December 31, 2007 is $781 million. Proved reserve estimates and related future net cash flows have been determined based on a year-end average realized gas price of $6.72 per Mcf and a year-end West Texas Intermediate posted oil price of $92.70 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 2008, 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, TrusteeBy:

          Nancy G. Willis Vice President

4

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, 2007 is approximately 14 years. This index is calculated using total proved reserves and estimated 2008 production for the underlying properties. The projected 2008 production is from proved developed producing reserves as of December 31, 2007. Based on estimated future net cash flows at year-end oil and gas prices, the proved reserves of the
underlying properties are approximately 89% natural gas and 11% 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, 2007, 2006 and 2005  Costs. Total 2007 development costs deducted for the underlying properties were $42.8 million, a decrease of 17% from the prior year. XTO Energy has informed the trustee that total 2008 budgeted development costs for the underlying
properties are approximately $46.0 million.

Hugoton Area

Discovered in 1922, the Hugoton area is one of the largest natural gas producing areas in the United States. During 2007, gas sales volumes from the underlying properties in the Hugoton area were 7.9 Bcf, or approximately 28% of total sales volumes from the underlying properties. Most of the production is from the Chase formation at depths of 2,700 to 2,900 feet. 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 41 workovers in 2007, of which 27 were Chase restimulations. XTO Energy has informed the trustee that it plans to drill up to seven wells and perform up to 25 workovers in this area during 2008.

Anadarko Basin

The Anadarko Basin of western Oklahoma was discovered in 1945. Gas sales volumes from the underlying properties in the Anadarko Basin totaled 12.3 Bcf in 2007, or approximately 44% 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 12 gross (6.4 net) wells and performed 31 workovers in 2007. XTO Energy has informed the trustee that it plans to drill up to 12 wells and perform up to 23 workovers in Major County during 2008. In Woodward County, XTO Energy drilled 11 gross (9.2 net) wells and performed seven workovers in 2007. XTO Energy has informed the trustee that it plans to drill up to eight wells and perform up to eight workovers in Woodward County during 2008.

In the Elk City field, XTO Energy drilled four gross (3.6 net) wells and performed eight workovers in 2007. XTO Energy has informed the trustee that it plans to drill two wells and perform four workovers within the Elk City field during 2008.

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 at depths ranging from 7,500 to 10,000 feet. Gas sales volumes from the underlying properties in the Green River Basin were 7.9 Bcf in 2007, or approximately 28% of total sales volumes from the underlying properties.

In 2007, XTO Energy completed six gross (6.0 net) wells and performed nine workovers. XTO Energy has informed the trustee that it plans to drill up to six wells and perform up to eight workovers in the Green

5

River Basin during 2008. 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, 2007:



Underlying Properties

          

          Net Profits InterestsProved Reserves(a)

          

          Proved Reserves(a)(b)

          

          Future Net Cash Flows from Proved Reserves(a)(c)(in Thousands)

          

          Gas (Mcf)

          

          Oil(Bbls)

          

          Gas(Mcf)

          

          Oil (Bbls)

          

          Undiscounted

          

          DiscountedOklahoma

          

          

          258,913

          

          

          

          3,440

          

          

          

          150,610

          

          

          

          2,006

          

          

          $

          1,169,679

          

          

          $

          581,990Wyoming

          

          

          117,550

          

          

          

          129

          

          

          

          59,902

          

          

          

          65

          

          

          

          337,461

          

          

          

          161,793Kansas

          

          

          29,010

          

          

          

          76

          

          

          

          14,436

          

          

          

          39

          

          

          

          67,901

          

          

          

          36,959Total

          

          

          405,473

          

          

          

          3,645

          

          

          

          224,948

          

          

          

          2,110

          

          

          $

          1,575,041

          

          

          $

          780,742




(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.

6

TRUSTEES DISCUSSION AND ANALYSIS

Years Ended December 31, 2007, 2006 and 2005

Net profits income for 2007 was $70,499,584, as compared with $91,241,196 for 2006 and $105,129,321 for 2005. The 23% decrease in net profits income from 2006 to 2007 is primarily the result of lower gas sales volumes and gas prices, partially offset by lower development costs. The 13% decrease in net profits income from 2005 to 2006 was primarily the result of higher development costs and production expense. Approximately 88% in 2007, 91% in 2006 and 92% in 2005 of net profits income was derived from natural gas sales.

Trust administration expense was $1,246,189 in 2007 as compared to $528,978 in 2006 and $410,083 in 2005. 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. Increased administration expense from 2005 to 2006 was primarily because of reporting costs related to an increased number of unitholders. Interest income was $135,125 in 2007, $198,542 in 2006 and $112,642 in 2005. Changes in interest income are attributable to fluctuations in net profits income and interest rates. Distributable income was $69,388,520 or
$1.734713 per unit in 2007, $90,910,760 or $2.272769 per unit in 2006 and $104,831,880 or $2.620797 per unit in 2005.

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 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. From 2005 to 2006, underlying gas sales volumes decreased 1% and underlying oil sales volumes increased 2%. Lower gas sales volumes were primarily because of natural production decline and the timing of cash receipts, which was largely offset by
increased production from new wells and workovers. Oil sales volumes increased primarily because of increased production from new wells and workovers and the timing of cash receipts, partially offset by natural production decline.

Prices

Gas.  The 2007 average gas price was $5.70 per Mcf, a 14% decrease from the 2006 average gas price of $6.59 per Mcf, which was 1% lower than the 2005 average gas price of $6.64 per Mcf. Natural gas prices rose sharply in the second half of 2005 due to the effects of hurricanes on Gulf of Mexico production. During most of 2006, gas prices trended lower primarily because of an adequate natural gas supply inventory due to the warmer than normal winter weather and the absence of hurricane activity in the Gulf of Mexico. Much colder temperatures in early 2007 caused prices to partially rebound, however, the absence of hurricane activity
in the Gulf of Mexico in 2007 has kept prices relatively flat. Prices will continue to be affected by weather, 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.

Gas prices in the Rocky Mountain region were significantly lower for April through November 2007 production primarily as a result of pipeline constraints and limited regional demand. This resulted in lower realized prices for the trusts Wyoming gas production for the June 2007 through January 2008 distributions to unitholders which, in turn, resulted in excess costs on properties underlying the Wyoming net profits interests (see Excess costs below). 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 have increased significantly and the
trusts realized gas prices and monthly distributions have improved. At February 11, 2008, the average futures price

7

for Wyoming gas for the following six months is expected to be approximately 16% lower than the NYMEX price. Wyoming gas production was approximately 28% of total trust gas production for the year ended December 31, 2007.

The trusts average realized gas price was $5.70 per Mcf, 18% lower than the average NYMEX price of $6.94 in 2007; $6.59 per Mcf, or 18%, lower than the average NYMEX price of $8.02 in 2006; and $6.64 per Mcf, or 18%, lower than the average NYMEX price of $8.10 in 2005. The average NYMEX price for November 2007 through January 2008 was $7.21 per MMBtu. At February 11, 2008, the average NYMEX gas price for the following 12 months was $8.98 per MMBtu. Recent trust gas prices have averaged approximately 16% lower than the NYMEX price.

Oil.  The average oil price for 2007 was $64.35 per Bbl, 1% higher than the average oil price for 2006 of $63.73 per Bbl, which was 22% higher than the average oil price for 2005 of $52.27 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 hurricanes in the Gulf of Mexico in 2005 and political instability. In the last few months of 2007 and early 2008, rising tension in the Middle East, weakness in the dollar and strong demand caused prices to reach record levels of $100.00 per Bbl.
Oil prices are expected to remain volatile. The average NYMEX price for November 2007 through January 2008 was $93.30 per Bbl. At February 11, 2008, the average NYMEX oil price for the following 12 months was $92.53 per Bbl. Recent trust oil prices have averaged approximately 4% lower than the NYMEX price.

See Gulf of Mexico Hurricanes below.

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 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 was relatively unchanged from 2006 to 2007 as increased labor and compressor rental costs were largely offset by decreased fuel costs. Production expense increased 20% from 2005 to 2006 primarily because of increased repair and maintenance and insurance costs as a result of increased activity and higher industry costs.

Development.  Development costs deducted were $42.8 million in 2007, $51.7 million in 2006 and $39.2 million in 2005. In 2007, actual development costs were $40.0 million. At December 31, 2007, cumulative actual costs exceeded cumulative budgeted costs deducted by approximately $0.7 million. Because of increased development activity and continued increasing costs, the monthly development cost deduction was increased twice in 2006. The deductions were increased to $4.2 million beginning with the April 2006 distribution and to $5.0 million beginning with the August 2006 distribution. With a reduction in development activity in first
quarter 2007 and based on the development budget for 2007, the development cost deduction was lowered to $3.75 million beginning with the February 2007 distribution. This monthly deduction was maintained for the remainder of 2007. 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.

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 moderate regional demand led to significantly lower realized regional gas prices for production (see Prices above). These lower gas prices caused costs to exceed revenues on

8

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 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 have increased and the excess costs, plus accrued interest of $10,090 ($8,072 net to the trust), were fully recovered by February 2008.

Gulf of Mexico Hurricanes

In late August and September 2005, hurricanes in the Gulf of Mexico disrupted a significant portion of U.S. oil and gas production, leading to higher and more volatile commodity prices. These increased prices began affecting distributions to unitholders beginning with the November 2005 distribution that was paid in December 2005. The underlying properties to the trust are not located near the Gulf and related production was not significantly affected. However, because of greater supply and weaker demand in areas where trust related oil and gas is produced, the price received for such production was significantly lower than NYMEX prices, which are
generally representative of the price received for gas delivered in the Louisiana Gulf coast region. This effect on prices had substantially diminished by the April 2006 distribution that was paid in May 2006. Production expense and development costs also increased throughout the industry because of storm damages and related supply shortages.

Fourth Quarter 2007 and 2006

During fourth quarter 2007 the trust received net profits income totaling $14,642,197 compared with fourth quarter 2006 net profits income of $14,067,286. This 4% increase in net profits income was primarily because of lower development costs and higher oil prices, partially offset by lower gas sales volumes and lower gas prices.

Administration expense was $104,367 and interest income was $27,730, resulting in fourth quarter 2007 distributable income of $14,565,560, or $0.364139 per unit. Distributable income for fourth quarter 2006 was $13,976,120 or $0.349403 per unit. Distributions to unitholders for the quarter ended December 31, 2007 were:



Record Date

          

          Payment Date

          

          Per UnitOctober 31, 2007

          

          

          November 15, 2007

          

          

          $

          0.134913November 30, 2007

          

          

          December 14, 2007

          

          

          

          0.098876December 31, 2007

          

          

          January 15, 2008

          

          

          

          0.130350$

          0.364139

Volumes

Fourth quarter underlying gas sales volumes decreased 4% and underlying oil sales volumes decreased 8% from 2006 to 2007. Gas and oil sales volumes decreased primarily because of natural production decline, partially offset by increased production from new wells and workovers. In addition, oil sales volumes were lower because of the timing of cash receipts.

Prices

The average fourth quarter 2007 gas price was $4.77 per Mcf, or 10% lower than the fourth quarter 2006 average price of $5.28 per Mcf. The average fourth quarter 2007 oil price was $75.10 per Bbl, or 21% higher than the fourth quarter 2006 average price of $62.05 per Bbl. For further information about product prices, see Years Ended December 31, 2007, 2006 and 2005  Prices above.

Costs

Taxes, Transportation and Other.  Taxes, transportation and other generally fluctuates with changes in total revenues. Taxes, transportation and other decreased 10% from 2006 to 2007 as compared to a 10% decrease in total revenues over the same period.

Production.  Fourth quarter production expense decreased 9% from 2006 to 2007 primarily because of decreased repair and maintenance, insurance and fuel costs, partially offset by increased labor costs.

9

Development.  Development costs, which were deducted based on budgeted development costs, decreased 25% from fourth quarter 2006 to 2007 primarily because of the timing of expenditures and lower costs.

Overhead.  Overhead increased 9% from fourth quarter 2006 to 2007 primarily because of an increased well count and the annual rate adjustment based on an oil and gas industry index.

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 limited regional demand led to significantly lower realized regional gas prices for production (see Years Ended December 31, 2007, 2006 and 2005  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 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 have increased and the excess costs, plus accrued interest of $10,090 ($8,072 net to the trust), were fully recovered by February 2008.

For further information about costs, see Years Ended December 31, 2007, 2006 and 2005  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.

10

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)2007

          

          2006

          

          2005

          

          2007

          

          2006Sales VolumesGas (Mcf)(b)Underlying properties

          

          

          28,092,224

          

          

          

          29,628,079

          

          

          

          29,986,698

          

          

          

          7,253,325

          

          

          

          7,565,251Average per day

          

          

          76,965

          

          

          

          81,173

          

          

          

          82,155

          

          

          

          78,840

          

          

          

          82,231Net profits interests

          

          

          11,233,503

          

          

          

          12,871,453

          

          

          

          15,836,681

          

          

          

          2,413,294

          

          

          

          2,386,820Oil (Bbls)(b)Underlying properties

          

          

          305,594

          

          

          

          332,525

          

          

          

          325,193

          

          

          

          82,039

          

          

          

          89,214Average per day

          

          

          837

          

          

          

          911

          

          

          

          891

          

          

          

          892

          

          

          

          970Net profits interests

          

          

          140,805

          

          

          

          145,230

          

          

          

          177,980

          

          

          

          34,495

          

          

          

          28,686Average Sales PricesGas (per Mcf)

          

          

          $5.70

          

          

          $

          6.59

          

          

          $

          6.64

          

          

          

          $4.77

          

          

          $

          5.28Oil (per Bbl)

          

          

          $64.35

          

          

          $

          63.73

          

          

          $

          52.27

          

          

          

          $75.10

          

          

          $

          62.05RevenuesGas sales

          

          

          $160,104,931

          

          

          $

          195,130,332

          

          

          $

          198,985,047

          

          

          

          $34,589,223

          

          

          $

          39,960,899Oil sales

          

          

          19,666,471

          

          

          

          21,190,530

          

          

          

          16,997,457

          

          

          

          6,160,932

          

          

          

          5,535,750Total Revenues

          

          

          179,771,402

          

          

          

          216,320,862

          

          

          

          215,982,504

          

          

          

          40,750,155

          

          

          

          45,496,649CostsTaxes, transportation and other

          

          

          18,429,983

          

          

          

          20,074,451

          

          

          

          19,113,977

          

          

          

          4,333,853

          

          

          

          4,838,884Production expense

          

          

          22,268,104

          

          

          

          22,231,559

          

          

          

          18,468,101

          

          

          

          5,391,813

          

          

          

          5,932,299Development costs(c)

          

          

          42,750,000

          

          

          

          51,700,000

          

          

          

          39,200,000

          

          

          

          11,250,000

          

          

          

          15,000,000Overhead

          

          

          9,052,303

          

          

          

          8,263,357

          

          

          

          7,788,775

          

          

          

          2,325,211

          

          

          

          2,141,358Excess costs(d)

          

          

          (853,468)

          

          

          

          

          

          

          

          

          

          

          

          (853,468

          )

          

          

          Total Costs

          

          

          91,646,922

          

          

          

          102,269,367

          

          

          

          84,570,853

          

          

          

          22,447,409

          

          

          

          27,912,541Net Proceeds

          

          

          88,124,480

          

          

          

          114,051,495

          

          

          

          131,411,651

          

          

          

          18,302,746

          

          

          

          17,584,108Net Profits Percentage

          

          

          80%

          

          

          

          80

          %

          

          

          80

          %

          

          

          80%

          

          

          

          80

          %Net Profits Income

          

          

          $ 70,499,584

          

          

          $

          91,241,196

          

          

          $

          105,129,321

          

          

          

          $ 14,642,197

          

          

          $

          14,067,286




(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.

11

HUGOTON ROYALTY TRUST

STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS



December 312007

          

          2006AssetsCash and short-term investments

          

          

          $ 5,214,000

          

          

          $

          1,813,000Net profits interests in oil and gas properties  net (Notes 1 and 2)

          

          

          155,820,033

          

          

          

          163,796,772$ 161,034,033

          

          

          $

          165,609,772Liabilities and Trust CorpusDistribution payable to unitholders

          

          

          $ 5,214,000

          

          

          $

          1,813,000Trust corpus (40,000,000 units of beneficial interest authorized and outstanding)

          

          

          155,820,033

          

          

          

          163,796,772$ 161,034,033

          

          

          $

          165,609,772

STATEMENTS OF DISTRIBUTABLE INCOME



Year Ended December 312007

          

          2006

          

          2005Net profits income

          

          

          $ 70,499,584

          

          

          $

          91,241,196

          

          

          $

          105,129,321Interest income

          

          

          135,125

          

          

          

          198,542

          

          

          

          112,642Total income

          

          

          70,634,709

          

          

          

          91,439,738

          

          

          

          105,241,963Administration expense

          

          

          1,246,189

          

          

          

          528,978

          

          

          

          410,083Distributable income

          

          

          $ 69,388,520

          

          

          $

          90,910,760

          

          

          $

          104,831,880Distributable income per unit (40,000,000 units)

          

          

          $ 1.734713

          

          

          $

          2.272769

          

          

          $

          2.620797

STATEMENTS OF CHANGES IN TRUST CORPUS



Year Ended December 312007

          

          2006

          

          2005Trust corpus, beginning of year

          

          

          $ 163,796,772

          

          

          $

          171,935,330

          

          

          $

          182,551,814Amortization of net profits interests

          

          

          (7,976,739)

          

          

          

          (8,138,558

          )

          

          

          (10,616,484

          )Distributable income

          

          

          69,388,520

          

          

          

          90,910,760

          

          

          

          104,831,880Distributions declared

          

          

          (69,388,520)

          

          

          

          (90,910,760

          )

          

          

          (104,831,880

          )Trust corpus, end of year

          

          

          $ 155,820,033

          

          

          $

          163,796,772

          

          

          $

          171,935,330

See Accompanying Notes to Financial Statements.

12

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:



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

13



          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.

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 $91,246,918 as of December 31, 2007 and $83,270,179 as of December 31, 2006.

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).

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 moderate regional demand 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 has 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 have increased and the excess costs, plus accrued interest of $10,090 ($8,072 net to the trust), were fully recovered by February 2008.

14

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 312007

          

          2006

          

          2005Cumulative actual costs (over) under the amount deducted  beginning of period

          

          

          $ (3,410,174)

          

          

          $

          113,905

          

          

          $

          (319,927

          )Actual costs

          

          

          (40,015,580)

          

          

          

          (55,224,079

          )

          

          

          (38,766,168

          )Budgeted costs deducted

          

          

          42,750,000

          

          

          

          51,700,000

          

          

          

          39,200,000Cumulative actual costs (over) under the amount deducted  end of period

          

          

          $ (675,754)

          

          

          $

          (3,410,174

          )

          

          $

          113,905

The monthly development deduction was increased twice during 2006 as a result of increased development activity and higher costs. The deductions were increased to $4.2 million beginning with the April 2006 distribution and to $5.0 million beginning with the August 2006 distribution. With a reduction in development activity in first quarter 2007 and based on the development budget for 2007, the development cost deduction was lowered to $3.75 million beginning with the February 2007 distribution. This monthly deduction was maintained for the remainder of 2007. 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.

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, 2007, the overhead charge was approximately $770,000 ($616,000 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 $76.6 million for 2007, or 48% of total gas sales, $103.2 million for 2006, or 53% of total gas sales and $107.9 million for 2005, or 54% of total gas sales.

15

8. 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.

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 has not been scheduled. 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.

16

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 2007 and 2006:



Net Profits Income

          

          Distributable Income

          

          Distributable Income per Unit2007First Quarter

          

          

          $16,735,385

          

          

          $

          16,242,280

          

          

          $

          0.406057Second Quarter

          

          

          21,251,246

          

          

          

          20,846,000

          

          

          

          0.521150Third Quarter

          

          

          17,870,756

          

          

          

          17,734,680

          

          

          

          0.443367Fourth Quarter

          

          

          14,642,197

          

          

          

          14,565,560

          

          

          

          0.364139$70,499,584

          

          

          

          $ 69,388,520

          

          

          $

          1.7347132006First Quarter

          

          $

          39,085,894

          

          

          $

          39,041,600

          

          

          $

          0.976040Second Quarter

          

          

          21,125,072

          

          

          

          20,972,240

          

          

          

          0.524306Third Quarter

          

          

          16,962,944

          

          

          

          16,920,800

          

          

          

          0.423020Fourth Quarter

          

          

          14,067,286

          

          

          

          13,976,120

          

          

          

          0.349403$

          91,241,196

          

          

          $

          90,910,760

          

          

          $

          2.272769

17

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, 2007 and 2006, and the related statements of distributable income and changes in trust corpus for each of the years in the three-year period ended December 31, 2007. These financial statements are the responsibility of the trustee. Our responsibility is to express an opinion on these financial statements 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 audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by the trustee, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our
opinion.

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.

In our opinion, the financial statements referred to above present fairly, in all material respects, the assets, liabilities, and trust corpus of the Hugoton Royalty Trust as of December 31, 2007 and 2006 and its distributable income and changes in trust corpus for each of the years in the three-year period ended December 31, 2007 in conformity with the modified cash basis of accounting described in note 2.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Hugoton Royalty Trusts internal control over financial reporting as of December 31, 2007, based on criteria established inInternal Control  Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 25, 2008, expressed an unqualified opinion on the effectiveness of the trusts internal control over financial reporting.

KPMG LLP

Dallas, Texas February 25, 2008

18

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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

We have audited Hugoton Royalty Trusts internal control over financial reporting as of December 31, 2007, based on criteria established in Internal Control  Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The trustee of the Hugoton Royalty Trust is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the trustees report on internal control over financial reporting. Our responsibility is to express an opinion on the trusts
internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit 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 audit also included performing such other procedures as we considered
necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

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, Hugoton Royalty Trust maintained, in all material respects, effective internal control over financial reporting as of December 31, 2007, based on criteria established in Internal Control  Integrated Framework issued by COSO.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the statements of assets, liabilities, and trust corpus of the Hugoton Royalty Trust as of December 31, 2007 and 2006, and the related statements of distributable income and changes in trust corpus for each of the years in the three-year period ended December 31, 2007, and our report dated February 25, 2008, expressed an unqualified opinion on those financial statements and included an explanatory paragraph that described the trusts method of accounting as explained in note 2 to the financial statements.

KPMG LLP

Dallas, Texas February 25, 2008

19

HUGOTON ROYALTY TRUST

901 Main Street, 17th Floor P.O. Box 830650 Dallas, Texas 75283-0650 (877) 228-5083 U.S. Trust, Bank of America Private Wealth Management, Trustee

A copy of the Hugoton Royalty Trust Form 10-K has been provided with this Annual Report. Additional copies of this Annual Report and Form 10-K will be provided to unitholders without charge upon request. Copies of exhibits to the Form 10-K may be obtained upon request or from the trusts web site at www.hugotontrust.com.

WEB SITE

www.hugotontrust.com

AUDITORS

KPMG LLP Dallas, Texas

LEGAL COUNSEL

Thompson & Knight L.L.P. Dallas, Texas

TAX COUNSEL

Winstead PC Houston, Texas

TRANSFER AGENT AND REGISTRAR

BNY Mellon Shareowner Serviceswww.bnymellon.com/shareowner

20