**Exhibit 13**

 

**HUGOTONROYALTY TRUST**

 

GLOSSARY OF TERMS

 

The following are definitions of significantterms 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 commonenergy measurement

 

*net proceeds*                                                                           Gross proceeds received by XTO Energy fromsale of production from the underlying properties, less applicable costs, asdefined in the net profits interest conveyances

 

*net profits income**                                              *Net proceeds multiplied by the net profitspercentage of 80%, which is paid to the trust by XTO Energy. “Net profitsincome” is referred to as “royalty income” for tax reporting purposes.

 

*net profits interest*                                             An interest in an oil and gas propertymeasured by net profits from the sale of production, rather than a specificportion of production. The following defined net profits interests wereconveyed to the trust from the underlying properties:

 

*80% net profits interests—*interests that entitle the trust to receive80% of the net proceeds from the underlying properties.

 

*underlying properties*                         XTO Energy’s interest in certain oil and gas properties from which thenet profits interests were conveyed. The underlying properties include workinginterests in predominantly gas-producing properties located in Kansas, Oklahomaand Wyoming.

 

*working interest*                                                      An operating interest in an oil and gasproperty that provides the owner a specified share of production that issubject to all production expense and development costs

 

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**THE TRUST**

 

Hugoton Royalty Trust was created on December1, 1998 when XTO Energy Inc. conveyed 80% net profits interests in certainpredominantly gas-producing properties located in Kansas, Oklahoma and Wyomingto the trust. The net profits interests are the only assets of the trust, otherthan cash held for trust expenses and for distribution to unitholders.

 

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

 

**UNITS OFBENEFICIAL INTEREST**

 

The units of beneficial interest in the trustbegan 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 cashdistributions per unit paid by the trust during each quarter of 2005 and 2004:

 
| ** **  | ** ** | **Sales Price** | ** ** | **Distributions** | ** ** |
|-------------|------------|-----------------|------------|-------------------|------------|
| **Quarter** | ** ** | **High**        | ** ** | **Low**           | ** ** | **per Unit** | ** ** |
| **2005**    |       |            |       |              |       |   |   |
|        |       |            |       |              |       |   |   |
| **First**   | ** ** | **$**           | **32.19**  | ** **        | **$**      | **23.72** | ** ** | **$** | **0.642454** | ** ** |
| **Second**  | ** ** | **31.05**       | ** ** | **24.88**         | ** ** | **0.570801** | ** ** |
| **Third**   | ** ** | **41.84**       | ** ** | **29.80**         | ** ** | **0.607605** | ** ** |
| **Fourth**  | ** ** | **41.80**       | ** ** | **31.03**         | ** ** | **0.799937** | ** ** |
| ** **  |       | ** **      |       | ** **        |       | **$** | **2.620797** |   |
|        |       |            |       |              |       |   |   |
| 2004        |       |            |       |              |       |   |   |
| First       |       | $               | 22.54      |              | $          | 17.10 |   | $ | 0.474419 |   |
| Second      |       | 24.40           |       | 19.60             |       | 0.454464 |   |
| Third       |       | 28.25           |       | 22.85             |       | 0.585721 |   |
| Fourth      |       | 29.95           |       | 24.75             |       | 0.525319 |   |
|        |       |            |       |              |       | $ | 2.039923 |   |

 

At December 31, 2005, there were 40,000,000units outstanding and approximately 192 unitholders of record; 17,587,316 ofthese units were held by depository institutions. As of December 31, 2005, XTOEnergy owned 21,705,893 units. In January 2006, the Board of Directors of XTOEnergy declared a dividend of all of the 21.7 million trust units it owns. Theseunits are to be distributed on May 12, 2006 to XTO Energy’s common stockholdersof record on April 26, 2006. After this dividend, XTO Energy will not be aunitholder of the trust.

 

XTO Energy also announced in January 2006that it will consider selling the underlying properties. Any sale is dependentupon XTO Energy’s ability to structure a tax-efficient transaction and receivesufficient consideration from a buyer it deems to be qualified.

 

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***Forward-Looking Statements***

 

*ThisAnnual Report, including the accompanying Form 10-K, includes “forward-lookingstatements” within the meaning of Section 27A of the Securities Act of 1933, asamended, and Section 21E of the Securities Exchange Act of 1934, as amended. Allstatements other than statements of historical fact included in this AnnualReport and Form 10-K, including, without limitation, statements regardingestimates of proved reserves, future development plans and costs, and industryand market conditions, are forward-looking statements that are subject to anumber of risks and uncertainties which are detailed in Part I, Item 1A of theaccompanyingForm 10-K. Although XTO Energy and the trustee believe that theexpectations reflected in such forward-looking statements are reasonable,neither XTO Energy nor the trustee can give any assurance that suchexpectations will prove to be correct.*

 

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**SUMMARY**

 

The trust was created to collect and distributeto unitholders monthly net profits income related to the 80% net profitsinterests. Such net profits income is calculated as 80% of the net proceedsreceived from certain working interests in predominantly gas-producingproperties in Kansas, Oklahoma and Wyoming. Net proceeds from properties ineach state are calculated by deducting production expense, development costsand overhead from revenues. If monthly costs exceed revenues from theunderlying properties in any state, such excess costs must be recovered, withaccrued interest, from future net proceeds of that state and cannot reduce netprofits income from another state. Excess costs generally can occur duringperiods of higher development activity and lower gas prices.

 

•                                    Cost Depletion is generally available tounitholders as a deduction from royalty income. Available depletion isdependent upon the unitholder’s cost of units, purchase date and priorallowable depletion. It may be more beneficial for unitholders to deductpercentage depletion. Unitholders should consult their tax advisors for furtherinformation.

 

*As an example, a unitholder that acquired units in January2005 and held them throughout 2005 would be entitled to a cost depletiondeduction of approximately 6% of his cost. Assuming a cost of $25.00 per unit,cost depletion would offset approximately 56% of 2005 taxable trust income. Assuminga 30% tax rate, the 2005 taxable equivalent return as a percentage of unit costwould be 13%. (NOTE—Because the units are a depleting asset, a portion of thisreturn is effectively a return of capital.)*

 

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**TOUNITHOLDERS**

 

We are pleased to present the 2005 AnnualReport of the Hugoton Royalty Trust. This report includes a copy of the trust’s2005 Form 10-K as filed with the Securities and Exchange Commission. Bothreports contain important information about the trust’s net profits interests,including information provided to the trustee by XTO Energy, and should be readin conjunction with each other.

 

For the year ended December 31, 2005, netprofits income totaled $105,129,321. After adding interest income of $112,642and deducting trust administration expense of $410,083, distributable incomewas $104,831,880 or $2.620797 per unit. Net profits income and distributionswere 28% higher than 2004 amounts primarily because of higher product prices,partially offset by increased development costs.

 

Natural gas prices averaged $6.64 per Mcf for2005, 33% higher than the 2004 average price of $4.99 per Mcf. The average 2005oil price was $52.27 per Bbl, 37% higher than the 2004 average price of $38.11per Bbl.

 

Gas sales volumes from the underlyingproperties for 2005 were 29,986,698 Mcf, or 82,155 Mcf per day, or a 1% declinefrom 82,619 Mcf per day in 2004. Oil sales volumes from the underlyingproperties were 325,193 Bbls, or 891 Bbls per day in 2005, or an increase of 2%from 871 Bbls per day in 2004. For further information on sales volumes andproduct prices, see “Trustee’s Discussion and Analysis.”

 

As of December 31, 2005, proved reserves forthe underlying properties were estimated by independent engineers to be 443.0Bcf of natural gas and 3.8 million Bbls of oil. Natural gas and oil reservesfor the underlying properties were relatively unchanged from year-end 2004primarily because production was offset by reserve additions from developmentactivity. Based on an allocation of these reserves, proved reservesattributable to the net profits interests were estimated to be 271.9 Bcf ofnatural gas and 2.4 million Bbls of oil. Estimated gas and oil reservesattributable to the net profits interests were relatively unchanged frompreviously reported reserves at year-end 2004, as the increase in allocatedreserves related to higher oil and gas prices was offset by a decreasedallocation for the effect of deducting overhead costs. All reserve informationprepared by independent engineers has been provided to the trustee by XTOEnergy.

 

Estimated future net cash flows from provedreserves of the net profits interests at December 31, 2005 are $2.32 billion,or $58.04 per unit. Using an annual discount factor of 10%, the present valueof estimated future net cash flows at December 31, 2005 is $1.11 billion,or $27.81 per unit. Proved reserve estimates and related future net cash flowshave been determined based on a year-end average realized gas price of $8.72per Mcf and a year-end West Texas Intermediate posted oil price of $57.75 perBbl. Other guidelines used in estimating proved reserves, as prescribed by theFinancial Accounting Standards Board, are described under Item 2 of theaccompanying Form 10-K. The present value of estimated future net cash flows isnot representative of the market value of trust units.

 

As disclosed in the tax instructions providedto unitholders in February 2006, trust distributions are considered portfolioincome, rather than passive income. Unitholders should consult their taxadvisors for further information.

 

Hugoton Royalty Trust

By: Bank of America, N.A., Trustee

 

 

By:            Nancy G. WillisVice President

 

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**THEUNDERLYING PROPERTIES**

 

The underlying properties are predominantlygas-producing properties with established production histories in the Hugotonarea of Oklahoma and Kansas, the Anadarko Basin of Oklahoma and the Green RiverBasin of Wyoming. The average reserve-to-production index for the underlyingproperties as of December 31, 2005 is approximately 15 years. This index iscalculated using total proved reserves and estimated 2006 production for theunderlying properties. The projected 2006 production is from proved developedproducing reserves as of December 31, 2005. Based on estimated future net cashflows at year-end oil and gas prices, the proved reserves of the underlying propertiesare approximately 94% natural gas and 6% oil. XTO Energy operates approximately94% of the underlying properties.

 

Because the underlying properties are workinginterests, production expense, development costs and overhead are deducted incalculating net profits income. As a result, net profits income is affected bythe level of maintenance and development activity on the underlying properties.See “Trustee’s Discussion and Analysis*—*YearsEnded December 31, 2005, 2004 and 2003*—*Costs.”  Total 2005 development costs deducted for theunderlying properties were $39.2 million, an increase of 84% from the prioryear. XTO Energy has informed the trustee that total 2006 budgeted developmentcosts for the underlying properties are approximately $40 million.

 

In January 2006, XTO Energy announced that itwill consider selling the underlying properties. Statements below regarding2006 development plans assume that XTO Energy will continue to own and operatethe underlying properties.

 

**HugotonArea**

 

Discovered in 1922, the Hugoton area is oneof the largest natural gas producing areas in the United States. During 2005,gas sales volumes from the underlying properties in the Hugoton area were 9.2Bcf, or approximately 31% of total sales volumes from the underlying properties.Most of the production is from the Chase formation at depths of 2,700 to 2,900feet. XTO Energy has informed the trustee that it plans to develop otherformations, including the Council Grove, Chester, Morrow and St. Louisformations that underlie the 79,500 net acres held by production by the Chaseformation wells. XTO Energy has participated in 3-D seismic shoots covering30,000 acres of its net acreage position beneath the Chase formation.

 

In 2005, XTO Energy successfully drilled fourgross (3.2 net) wells in the Hugoton area and continued its restimulationprogram in the Chase intervals, completing 55 of these restimulations. XTOEnergy has informed the trustee that it plans to drill up to ten wells andperform 50 Chase restimulations during 2006. Some of the Chase restimulationsinvolve adding perforations in a tighter interval of the formation that waspreviously bypassed.

 

**AnadarkoBasin**

 

The Anadarko Basin of western Oklahoma wasdiscovered in 1945. Gas sales volumes from the underlying properties in theAnadarko Basin totaled 12.5 Bcf in 2005, or approximately 42% of total salesvolumes from the underlying properties. XTO Energy is one of the largestproducers in the Ringwood, Northwest Okeene

 

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and Cheyenne Valley fields in Major County,the principal producing region of the underlying properties in the AnadarkoBasin.

 

In Major and Woodward counties, theMississippian (Osage), Chester and Red Fork formations were the primarydrilling targets in 2005. In Major County, XTO Energy successfully drilled tengross (6.5 net) wells and performed nine workovers. XTO Energy has informed thetrustee that it plans to drill up to 13 wells and perform up to 15 workovers inMajor County in 2006. The most significant increase in 2005 new well productionoccurred in Woodward County, where 12 gross (11.3 net) wells were successfullydrilled and completed in the Chester formation and four workovers wereperformed. XTO Energy has informed the trustee that it plans to drill up to tenwells and perform up to eight workovers in Woodward County during 2006.

 

**Green RiverBasin**

 

The Green River Basin is located insouthwestern Wyoming. Natural gas was discovered in the Fontenelle Field of theGreen River Basin in the early 1970s. The producing reservoirs are theCretacious-aged Frontier and Dakota sandstones at depths ranging from 7,500 to10,000 feet. Gas sales volumes from the underlying properties in the GreenRiver Basin were 8.3 Bcf in 2005, or approximately 27% of total sales volumesfrom the underlying properties.

 

In 2005, XTO Energy successfully drilledseven gross (seven net) wells and performed ten workovers. XTO Energy plans toperform up to ten workovers and may drill up to ten wells in the Green River Basinduring 2006. XTO Energy also plans to further test reduction in pipelinepressure which has recently shown potential for increasing production in theFontenelle Field.

 

**EstimatedProved Reserves and Future Net Cash Flows**

 

The following are proved reserves of theunderlying properties, as estimated by independent engineers, and provedreserves and future net cash flows from proved reserves of the net profitsinterests, based on an allocation of these reserves, at December 31, 2005:

 
| ** **         | ** ** | **Underlying Properties**  | ** ** | **Net Profits Interests** | ** ** |
|--------------------|------------|----------------------------|------------|---------------------------|------------|
| ** **         | ** ** | **Proved Reserves****(a)** | ** ** | **Proved Reserves(a)(b)** | ** ** | **Future Net Cash Flows** | ** ** |
| ** **         | ** ** | **Gas**                    | ** ** | **Oil**                   | ** ** | **Gas** | ** ** | **Oil** | ** ** | **from Proved Reserves(a)(c)** | ** ** |
| **(in thousands)** | ** ** | **(Mcf)**                  | ** ** | **(Bbls)**                | ** ** | **(Mcf)** | ** ** | **(Bbls)** | ** ** | **Undiscounted** | ** ** | **Discounted** | ** ** |
| ** **         | ** ** | ** **                 | ** ** | ** **                | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Oklahoma           |       | 266,975                    |       | 3,487                     |       | 172,962 |   | 2,263 |   | $ | 1,531,533 |   | $ | 744,801 |   |
| Wyoming            |       | 139,507                    |       | 157                       |       | 76,642 |   | 86 |   | 641,097 |   | 291,479 |   |
| Kansas             |       | 36,562                     |       | 137                       |       | 22,327 |   | 84 |   | 149,100 |   | 76,065 |   |
|               |       |                       |       |                      |       |   |   |   |   |   |   |   |   |   |   |
| TOTAL              |       | 443,044                    |       | 3,781                     |       | 271,931 |   | 2,433 |   | $ | 2,321,730 |   | $ | 1,112,345 |   |

 

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(a)                Based on year-end oil and gas prices. Forfurther information regarding trust proved reserves, see Item 2 of theaccompanying Form 10-K.

 

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(b)               Since the trust has defined net profitsinterests, the trust does not own a specific percentage of the oil and gasreserves. Because trust reserve quantities are determined using an allocationformula, any fluctuations in actual or assumed prices or costs will result inrevisions to the estimated reserve quantities allocated to the net profitsinterests.

 

(c)                Before income taxes since future net cashflows are not subject to taxation at the trust level.

 

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**TRUSTEE’SDISCUSSION AND ANALYSIS**

 

**Years EndedDecember 31, 2005, 2004 and 2003**

 

Net profits income for 2005 was $105,129,321,as compared with $81,920,014 for 2004 and $80,687,778 for 2003. The 28%increase in net profits income from 2004 to 2005 is primarily the result ofhigher product prices, partially offset by increased development costs. The 2%increase in net profits income from 2003 to 2004 was primarily the result ofhigher product prices, partially offset by increased development costs andlower sales volumes. Over 90% of net profits income in each year wasattributable to natural gas sales.

 

Trust administration expense was $410,083 in2005 as compared to $357,891 in 2004 and $344,280 in 2003. Increasedadministration expense has been primarily because of fees related to the auditof the trust’s internal control over financial reporting. Interest income was$112,642 in 2005, $34,797 in 2004 and $29,622 in 2003. Changes in interestincome are attributable to fluctuations in net profits income and interestrates. Distributable income was $104,831,880 or $2.620797 per unit in 2005,$81,596,920 or $2.039923 per unit in 2004 and $80,373,120 or $2.009328 per unitin 2003.

 

Net profits income is recorded when receivedby the trust, which is the month following receipt by XTO Energy, and generallytwo months after oil and gas production. Net profits income is generallyaffected by three major factors:

 

•                  oiland gas sales volumes,

•                  oiland gas sales prices, and

•                  costsdeducted in the calculation of net profits income.

 

***Volumes***

 

From 2004 to 2005, underlying gas salesvolumes decreased 1% and underlying oil sales volumes increased 2%. Lower gassales volumes are primarily because of natural production decline and thetiming of cash receipts, partially offset by increased production from new wellsand workovers. Oil sales volumes increased primarily because of increasedproduction from new wells and workovers and the timing of cash receipts,partially offset by natural production decline. From 2003 to 2004, underlyingoil and gas sales volumes decreased 4% primarily because of natural productiondecline, partially offset by increased production from new wells and workovers.

 

***Prices***

 

*Gas.*The 2005 average gas price was $6.64 per Mcf,a 33% increase from the 2004 average gas price of $4.99 per Mcf, which was 10%higher than the 2003 average gas price of $4.54 per Mcf. Since late 2002, gasprices have generally been increasing due primarily to increased demand anddeclining North American production. These trends accelerated in the secondhalf of 2005 due to the effects of hurricanes on Gulf of Mexico production. Duringthe last half of 2005 and the first two months of 2006, gas prices have rangedfrom a high in excess of $15.00 per MMBtu to a low of almost $6.50 per MMBtu. Priceswill continue to be affected by weather, the U.S. economy, the level of NorthAmerican production, crude oil prices and import levels of liquified naturalgas. In any case, natural gas prices are expected to remain volatile. Priceswill continue to be affected by weather, the U.S. economy, the level of NorthAmerican production, crude oil prices and import levels of liquified naturalgas. In any case, natural gas prices are expected to remain volatile.

 

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The trust’s average gas price was $0.75, or14%, lower than the average NYMEX price of $5.29 in 2003; $0.93, or 16%, lowerthan the average NYMEX price of $5.92 in 2004; and $1.46, or 18%, lower thanthe average NYMEX price of $8.10 in 2005. NYMEX prices are generallyrepresentative of the price received for gas delivered in the Louisiana Gulfcoast region, where demand is higher and supply has been diminished sinceAugust 2005 because of the Gulf hurricanes. Because of greater supply andweaker demand in the Mid-Continent and Rocky Mountain regions, where gas fromthe underlying properties is delivered and sold, trust gas prices have notrisen as dramatically as NYMEX prices. This has resulted in a wideningdecrement between the NYMEX and trust average gas prices. Recent trust gas priceswere approximately 25% lower than the NYMEX price. The average NYMEX price forJanuary and February 2006 was $8.37 per MMBtu.

 

*Oil.*The average oil price for 2005 was $52.27 perBbl, 37% higher than the average oil price for 2004 of $38.11 per Bbl, whichwas 26% higher than the 2003 average oil price of $30.13 per Bbl. Since late2002, oil prices have generally been rising primarily because of increasingglobal demand and supply shortage concerns, inadequate refining capacity,reduced production as a result of tropical storms and hurricanes in the Gulf ofMexico and political instability. Oil prices increased to record levels inAugust 2005, exceeding $70.00 per Bbl. Oil prices are expected to remainvolatile. The average NYMEX price for January and February 2006 was $63.67. Recenttrust oil prices have averaged approximately $1.70, or 3%, lower than the NYMEXprice.

 

See “Gulf of Mexico Hurricanes” below.

 

***Costs***

 

The calculation of net profits incomeincludes deductions for production expense, development costs and overheadsince the related underlying properties are working interests. If monthly costsexceed revenues for any state, these excess costs must be recovered, withaccrued interest, from future net proceeds of that state and cannot reduce netprofits income from another state. There have been no excess costs or relatedrecoveries since September 1999.

 

*Taxes,transportation and other.*Taxes, transportation and other generally fluctuates with changes intotal revenues.

 

*Production.* Production expense increased 3% from 2004 to2005 because of increased fuel costs and 6% from 2003 to 2004 primarily becauseof the timing of maintenance projects as well as increased fuel costs.

 

*Development.*Development costsdeducted were $39.2 million in 2005, $21.3 million in 2004 and $12.9 million in2003. Increased development costs are attributable to the timing of budgeteddevelopment projects to benefit from higher gas prices. Development costs havealso risen because of limited availability of drilling rigs, supplies and laborduring a period of rising demand for these resources.

 

In 2005, underlying budgeted developmentcosts deducted from distributions totaled $39.2 million, compared with actualdevelopment costs of $38.8 million. At December 31, 2005, cumulative budgetedcosts deducted exceeded cumulative actual development costs by approximately$114,000. Because of increased development activity and higher costs, themonthly development cost deduction was increased three times in 2005. Thedeductions were increased to $2.4 million beginning with the February 2005distribution, to $3.3 million beginning with the July 2005 distribution and to$5.1 million beginning with the October 2005 distribution. Development projectswere accelerated in the third and fourth quarter of 2005 because of gas

 

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supply disruptions and higher prices. With areduction in development activity in first quarter 2006 and based on thedevelopment budget for 2006, the development cost deduction was lowered to $3.3million beginning with the January 2006 distribution. XTO Energy has advisedthe trustee that this monthly deduction is expected to be maintained at leastthrough the March 2006 distribution, but will be evaluated and revised asnecessary.

 

*Overhead.*Overhead is charged by XTO Energy foradministrative expenses incurred to support operations of the underlyingproperties. Overhead fluctuates based on changes in the active well count anddrilling activity on the underlying properties, as well as an annual inflationadjustment.

 

***Litigation Settlement***

 

In July 2003, XTO Energy disbursed funds infinal settlement of the class action lawsuit, *Booth,et al. v. Cross Timbers Oil Company*. The portion of this settlementrelated to the production from the underlying properties since December 1,1998, the effective date of the trust, was $1,040,831. The settlement reducedroyalty income paid to the trust in August 2003 and the distribution paid tounitholders in September 2003 by $832,665, or $0.021 per unit.

 

***Gulf of Mexico Hurricanes***

 

In late August and September 2005, hurricanesin the Gulf of Mexico disrupted a significant portion of U.S. oil and gasproduction, leading to higher and more volatile commodity prices. Theseincreased prices began affecting distributions to unitholders beginning withthe November 2005 distribution that was paid in December 2005. The underlyingproperties to the trust are not located near the Gulf and related productionwas not significantly affected. However, because of greater supply and weakerdemand in areas where trust related oil and gas is produced, the price receivedfor such production has been significantly lower than the price received forGulf production or NYMEX prices. Production expense and development costs haveincreased throughout the industry because of storm damages and related supplyshortages.

 

**FourthQuarter 2005 and 2004**

 

During fourth quarter 2005 the trust receivednet profits income totaling $32,018,800 compared with fourth quarter 2004 netprofits income of $21,051,715. The 52% increase in net profits income fromfourth quarter 2004 to 2005 was primarily because of higher product prices andsales volumes, partially offset by higher development costs.

 

Administration expense was $62,453 andinterest income was $41,133, resulting in fourth quarter 2005 distributableincome of $31,997,480, or $0.799937 per unit. Distributable income for fourthquarter 2004 was $21,012,760 or $0.525319 per unit. Distributions tounitholders for the quarter ended December 31, 2005 were:

 
| **Record Date**    | ** ** | **Payment Date**   | ** ** | **Per Unit** | ** ** |
|--------------------|------------|--------------------|------------|--------------|------------|
| October 31,  2005  |       | November 15,  2005 |       | $            | 0.188586   |   |
| November 30,  2005 |       | December 14,  2005 |       | 0.273244     |       |
| December 30,  2005 |       | January 17,  2006  |       | 0.338107     |       |
|               |       |               |       | $            | 0.799937   |   |

 

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***Volumes***

 

Fourth quarter underlying gas and oil salesvolumes increased 2% from 2004 to 2005. Increased volumes are primarily becauseof increased production from new wells and workovers, partially offset bynatural production decline and the timing of cash receipts.

 

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***Prices***

 

The average fourth quarter 2005 gas price was$8.24 per Mcf, or 61% higher than the fourth quarter 2004 average price of$5.11 per Mcf. The average fourth quarter oil price was $60.80  per Bbl, or 30% higher than the fourthquarter 2004 average price of $46.73 per Bbl. For further information aboutproduct prices, see “Years Ended December 31, 2005, 2004 and 2003*—*Prices” above.

 

***Costs***

 

*Taxes,transportation and other.*Taxes, transportation and other generally fluctuates with changes intotal revenues.

 

*Production.*Fourth quarterproduction expense increased 21% from 2004 to 2005 primarily because of thetiming of maintenance projects and increased fuel costs.

 

*Development.*Development costs,which were deducted based on budgeted development costs, increased 155% fromfourth quarter 2004 to 2005 because of increased development activity andhigher costs.

 

*Overhead.*Overhead increased 4% from fourth quarter2004 to 2005 primarily because of the annual rate adjustment based on an oiland gas industry index.

 

For further information about costs, see “YearsEnded December 31, 2005, 2004 and 2003*—*Costs”above.

 

See Item 7 of the accompanying Form 10-K fordisclosures regarding liquidity and capital resources,  off-balance sheet arrangements, contractualobligations and commitments, related party transactions and critical accountingpolicies of the trust. See Item 7A of the accompanying Form 10-K forquantitative and qualitative disclosures about market risk affecting the trust.

 

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**Calculationof Net Profits Income**

 

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

 
| ** **                      | ** ** | ** **                    | ** **      | ** **               | ** ** | ** **  | ** ** | **Three Months** | ** **  |
|---------------------------------|------------|-------------------------------|-----------------|--------------------------|------------|-------------|------------|------------------|-------------|
| ** **                      | ** ** | **Year Ended December 31(a)** | ** **      | **Ended December 31(a)** | ** ** |
| ** **                      | ** ** | **2005**                      | ** **      | **2004**                 | ** ** | **2003**    | ** ** | **2005**         | ** **  | **2004** | ** ** |
| **Sales  Volumes**              |       |                          |            |                     |       |        |       |             |        |   |   |
| Gas (Mcf)*(b)*                  |       |                          |            |                     |       |        |       |             |        |   |   |
| Underlying properties           | ** ** | **29,986,698**                |            | 30,238,663               |       | 31,490,564  | ** ** | **7,644,787**    |        | 7,506,690 |   |
| Average per day                 | ** ** | **82,155**                    |            | 82,619                   |       | 86,276      | ** ** | **83,096**       |        | 81,594 |   |
| Net profits interests           | ** ** | **15,836,681**                |            | 16,462,378               |       | 17,832,189  | ** ** | **3,802,922**    |        | 4,064,480 |   |
|                            | ** ** | ** **                    |            |                     |       |        | ** ** | ** **       |        |   |   |
| Oil (Bbls)*(b)*                 |       |                          |            |                     |       |        |       |             |        |   |   |
| Underlying properties           | ** ** | **325,193**                   |            | 318,694                  |       | 331,867     | ** ** | **79,788**       |        | 78,329 |   |
| Average per day                 | ** ** | **891**                       |            | 871                      |       | 909         | ** ** | **867**          |        | 851 |   |
| Net profits interests           | ** ** | **177,980**                   |            | 184,487                  |       | 196,005     | ** ** | **46,056**       |        | 46,350 |   |
|                            | ** ** | ** **                    |            |                     |       |        | ** ** | ** **       |        |   |   |
| **Average  Sales Prices**       |       |                          |            |                     |       |        |       |             |        |   |   |
| Gas (per Mcf)                   | ** ** | **$**                         | **6.64**        |                     | $          | 4.99        |       | $                | 4.54        | ** ** | **$** | **8.24** |   | $ | 5.11 |   |
| Oil (per Bbl)                   | ** ** | **$**                         | **52.27**       |                     | $          | 38.11       |       | $                | 30.13       | ** ** | **$** | **60.80** |   | $ | 46.73 |   |
|                            | ** ** | ** **                    |            |                     |       |        | ** ** | ** **       |        |   |   |
| **Revenues**                    |       |                          |            |                     |       |        |       |             |        |   |   |
| Gas sales                       | ** ** | **$**                         | **198,985,047** |                     | $          | 151,041,142 |       | $                | 142,846,720 | ** ** | **$** | **63,029,136** |   | $ | 38,383,949 |   |
| Oil sales                       | ** ** | **16,997,457**                |            | 12,144,887               |       | 9,999,958   | ** ** | **4,851,445**    |        | 3,660,414 |   |
| Total Revenues                  | ** ** | **215,982,504**               |            | 163,186,029              |       | 152,846,678 | ** ** | **67,880,581**   |        | 42,044,363 |   |
|                            | ** ** | ** **                    |            |                     |       |        | ** ** | ** **       |        |   |   |
| **Costs**                       |       |                          |            |                     |       |        |       |             |        |   |   |
| Taxes, transportation and other | ** ** | **19,113,977**                |            | 14,029,943               |       | 13,552,224  | ** ** | **5,583,726**    |        | 3,699,487 |   |
| Production expense              | ** ** | **18,468,101**                |            | 17,893,352               |       | 16,889,700  | ** ** | **4,979,279**    |        | 4,120,919 |   |
| Development costs*(c)*          | ** ** | **39,200,000**                |            | 21,300,000               |       | 12,949,343  | ** ** | **15,300,000**   |        | 6,000,000 |   |
| Overhead                        | ** ** | **7,788,775**                 |            | 7,562,716                |       | 7,556,090   | ** ** | **1,994,076**    |        | 1,909,313 |   |
| Litigation                      |       | **—**                    |            | —                   |       | 1,040,831   |       | **—**       |        | — |   |
| Total Costs                     | ** ** | **84,570,853**                |            | 60,786,011               |       | 51,988,188  | ** ** | **27,857,081**   |        | 15,729,719 |   |
|                            | ** ** | ** **                    |            |                     |       |        | ** ** | ** **       |        |   |   |
| **Other  Proceeds**             |       |                          |            |                     |       |        |       |             |        |   |   |
| Property sales                  |       | **—**                    |            | —                   |       | 1,232       |       | **—**       |        | — |   |
|                            |       |                          |            |                     |       |        |       |             |        |   |   |
| **Net  Proceeds**               | ** ** | **131,411,651**               |            | 102,400,018              |       | 100,859,722 | ** ** | **40,023,500**   |        | 26,314,644 |   |
| ** **                      | ** ** | ** **                    |            |                     |       |        | ** ** | ** **       |        |   |   |
| **Net  Profits Percentage**     | ** ** | **80**                        | **%**           | 80                       | %          | 80          | %          | **80**           | **%**       | 80 | % |
| ** **                      | ** ** | ** **                    |            |                     |       |        | ** ** | ** **       |        |   |   |
| **Net  Profits Income**         | ** ** | **$**                         | **105,129,321** |                     | $          | 81,920,014  |       | $                | 80,687,778  | ** ** | **$** | **32,018,800** |   | $ | 21,051,715 |   |

 

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*(a)*       Becauseof the two-month interval between time of production and receipt of net profitsincome by the trust: 1) oil and gas sales for the year ended December 31generally relate to twelve months of production for the period November throughOctober, and 2) oil and gas sales for the three months ended December 31generally relate to production for the period August through October.

 

*(b)*       Oil andgas sales volumes are allocated to the net profits interests based upon aformula that considers oil and gas prices and the total amount of productionexpense and development costs. Changes in any of these factors may result in disproportionatefluctuations in volumes allocated to the net profits interests. Therefore,comparative discussion of oil and gas sales volumes is based on the underlyingproperties.

 

*(c)*        See Note4 to Financial Statements.

 

13

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**HUGOTONROYALTY TRUST**

 

STATEMENTS OF ASSETS, LIABILITIES AND TRUSTCORPUS

 
| ** **                                                                         | ** ** | **December 31** | ** **      |
|------------------------------------------------------------------------------------|------------|-----------------|-----------------|
| ** **                                                                         | ** ** | **2005**        | ** **      | **2004** | ** ** |
| Assets                                                                             |       |            |            |   |   |
|                                                                               |       |            |            |   |   |
| Cash and short-term investments                                                    | ** ** | **$**           | **13,524,280**  |   | $ | 6,947,520 |   |
|                                                                               |       |            |            |   |   |
| Net profits interests in oil and gas  properties*—*net (Notes 1 and 2)        | ** ** | **171,935,330** |            | 182,551,814 |   |
|                                                                               | ** ** | ** **      |            |   |   |
| ** **                                                                         |       | **$**           | **185,459,610** |   | $ | 189,499,334 |   |
| ** **                                                                         |       | ** **      |            |   |   |
| Liabilities  and Trust Corpus                                                      |       |            |            |   |   |
|                                                                               |       |            |            |   |   |
| Distribution payable to unitholders                                                | ** ** | **$**           | **13,524,280**  |   | $ | 6,947,520 |   |
|                                                                               | ** ** | ** **      |            |   |   |
| Trust corpus (40,000,000 units of  beneficial interest authorized and outstanding) | ** ** | **171,935,330** |            | 182,551,814 |   |
|                                                                               | ** ** | ** **      |            |   |   |
| ** **                                                                         |       | **$**           | **185,459,610** |   | $ | 189,499,334 |   |

 

STATEMENTS OF DISTRIBUTABLE INCOME

 
| ** **                                        | ** ** | **Year Ended December 31** | ** **      |
|---------------------------------------------------|------------|----------------------------|-----------------|
| ** **                                        | ** ** | **2005**                   | ** **      | **2004** | ** ** | **2003** | ** ** |
|                                              | ** ** | ** **                 |            |   |   |   |   |
| Net profits  income                               | ** ** | **$**                      | **105,129,321** |   | $ | 81,920,014 |   | $ | 80,687,778 |   |
|                                              | ** ** | ** **                 |            |   |   |   |   |
| Interest  income                                  | ** ** | **112,642**                |            | 34,797 |   | 29,622 |   |
|                                              | ** ** | ** **                 |            |   |   |   |   |
| Total income                                      | ** ** | **105,241,963**            |            | 81,954,811 |   | 80,717,400 |   |
|                                              | ** ** | ** **                 |            |   |   |   |   |
| Administration  expense                           | ** ** | **410,083**                |            | 357,891 |   | 344,280 |   |
|                                              | ** ** | ** **                 |            |   |   |   |   |
| Distributable income                              | ** ** | **$**                      | **104,831,880** |   | $ | 81,596,920 |   | $ | 80,373,120 |   |
|                                              | ** ** | ** **                 |            |   |   |   |   |
| Distributable income per unit (40,000,000  units) | ** ** | **$**                      | **2.620797**    |   | $ | 2.039923 |   | $ | 2.009328 |   |

 

SeeAccompanying Notes to Financial Statements.

 

14

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**HUGOTONROYALTY TRUST**

 

STATEMENTS OF CHANGES IN TRUST CORPUS

 
| ** **                             | ** ** | **Year Ended December 31** | ** **      |
|----------------------------------------|------------|----------------------------|-----------------|
| ** **                             | ** ** | **2005**                   | ** **      | **2004** | ** ** | **2003** | ** ** |
|                                   | ** ** | ** **                 |            |   |   |   |   |
| Trust  corpus, beginning of year       | ** ** | **$**                      | **182,551,814** | ** ** | $ | 193,245,847 |   | $ | 205,493,243 |   |
|                                   | ** ** | ** **                 | ** **      |   |   |   |   |
| Amortization  of net profits interests | ** ** | **(10,616,484**            | **)**           | (10,694,033 | ) | (12,247,396 | ) |
|                                   | ** ** | ** **                 | ** **      |   |   |   |   |
| Distributable  income                  | ** ** | **104,831,880**            | ** **      | 81,596,920 |   | 80,373,120 |   |
|                                   | ** ** | ** **                 | ** **      |   |   |   |   |
| Distributions  declared                | ** ** | **(104,831,880**           | **)**           | (81,596,920 | ) | (80,373,120 | ) |
|                                   | ** ** | ** **                 | ** **      |   |   |   |   |
| Trust  corpus, end of year             | ** ** | **$**                      | **171,935,330** | ** ** | $ | 182,551,814 |   | $ | 193,245,847 |   |

 

SeeAccompanying Notes to Financial Statements.

 

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**Hugoton  RoyaltyTrust**

 

NOTES TO FINANCIAL STATEMENTS

 

**1.****          ****Trust Organization andProvisions**

 

HugotonRoyalty Trust was created on December 1, 1998 by XTO Energy Inc. (formerlyknown as “Cross Timbers Oil Company”). Effective on that date, XTO Energyconveyed 80% net profits interests in certain predominantly gas-producingworking interest properties in Kansas, Oklahoma and Wyoming to the trust underseparate conveyances for each of the three states. XTO Energy currently ownsand operates the majority of the underlying working interest properties.

 

Inexchange for the conveyances of the net profits interests to the trust, XTOEnergy received 40 million units of beneficial interest in the trust. In Apriland May 1999, XTO Energy sold a total of 17 million units in the trust’sinitial public offering. In 1999 and 2000, XTO Energy also sold 1.3 millionunits to certain of its officers. The trust did not receive any proceeds fromthe sale of trust units. See Note 6.

 

Bankof America, N.A. is the trustee for the trust. The trust indenture provides,among other provisions, that:

 

•                the trust cannot engage in any businessactivity or acquire any assets other than the net profits interests andspecific short-term cash investments;

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

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

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

•                the trustee will make monthly cashdistributions to unitholders (Note 3); and

•                the trust will terminate upon the firstoccurrence of:

•                disposition of all net profits interestspursuant to terms of the trust indenture,

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

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

 

**2.****         ****Basis of Accounting**

 

Thefinancial statements of the trust are prepared on the following basis and arenot intended to present financial position and results of operations inconformity with U.S. generally accepted accounting principles:

 

•                Net profits income is recorded in the monthreceived by the trustee (Note 3).

•                Trust expenses are recorded based onliabilities paid and cash reserves established by the trustee for liabilitiesand contingencies.

•                Distributions to unitholders are recordedwhen declared by the trustee (Note 3).

 

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Themost significant differences between the trust’s financial statements and thoseprepared in accordance with U.S. generally accepted accounting principles are:

 

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

•                Expenses are recognized when paid rather thanwhen incurred.

•                Cash reserves may be established by thetrustee for contingencies that would not be recorded under generally acceptedaccounting principles.

 

Thiscomprehensive basis of accounting other than U.S. generally accepted accountingprinciples corresponds to the accounting permitted for royalty trusts by theU.S. Securities and Exchange Commission, as specified by Staff AccountingBulletin Topic 12:E, Financial Statements of Royalty Trusts.

 

Mostaccounting pronouncements apply to entities whose financial statements areprepared in accordance with U.S. generally accepted accounting principles,directing such entities to accrue or defer revenues and expenses in a periodother than when such revenues were received or expenses were paid. Because thetrust’s financial statements are prepared on the modified cash basis, asdescribed above, most accounting pronouncements are not applicable to the trust’sfinancial statements.

 

Theinitial carrying value of the net profits interests of $247,066,951 was XTOEnergy’s historical net book value of the interests on December 1, 1998, thedate of the transfer to the trust. Amortization of the net profits interests iscalculated on a unit-of-production basis and charged directly to trust corpus. Accumulatedamortization was $75,131,621 as of December 31, 2005 and $64,515,137 as ofDecember 31, 2004.

 

**3.****         ****Distributions to Unitholders**

 

Thetrustee determines the amount to be distributed to unitholders each month bytotaling net profits income, interest income and other cash receipts, andsubtracting liabilities paid and adjustments in cash reserves established bythe trustee. The resulting amount is distributed to unitholders of recordwithin ten business days after the monthly record date, which is the lastbusiness day of the month.

 

Netprofits income received by the trustee consists of net proceeds received in theprior month by XTO Energy from the underlying properties, multiplied by 80%. Netproceeds are the gross proceeds received from the sale of production, lesscosts. Costs generally include applicable taxes, transportation, legal andmarketing charges, production expense, development and drilling costs, andoverhead (Note 6).

 

XTOEnergy, as owner of the underlying properties, computes net profits incomeseparately for each of the three conveyances (one for each of the states ofKansas, Oklahoma and Wyoming). If costs exceed revenues for any conveyance,such excess costs must be recovered, with accrued interest, from future netproceeds of that conveyance and cannot reduce net profits income from the otherconveyances.

 

17

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**4.****         ****Development Costs**

 

Thefollowing summarizes actual development costs, budgeted development costsdeducted in the calculation of net profits income, and the cumulative actualcosts compared to the amount deducted:

 
| ** **                                                                           | ** ** | **Development Costs**      | ** **   |
|--------------------------------------------------------------------------------------|------------|----------------------------|--------------|
| ** **                                                                           | ** ** | **Year Ended December 31** | ** **   |
| ** **                                                                           | ** ** | **2005**                   | ** **   | **2004** | ** ** | **2003** | ** ** |
| Cumulative actual costs (over) under the  amount deducted*—*beginning of period | ** ** | **$**                      | **(319,927** | **)** | $ | (1,583,988 | ) | $ | 3,089,563 |   |
| Actual costs                                                                         | ** ** | **(38,766,168**            | **)**        | (20,035,939 | ) | (17,622,894 | ) |
| Budgeted costs deducted                                                              | ** ** | **39,200,000**             | ** **   | 21,300,000 |   | 12,949,343 |   |
| Cumulative actual costs (over) under the  amount deducted*—*end of period       | ** ** | **$**                      | **113,905**  | ** ** | $ | (319,927 | ) | $ | (1,583,988 | ) |

 

Themonthly development deduction was $2 million in January 2005, but was increasedthree times during 2005 as a result of increased development activity andhigher costs. The deductions were increased to $2.4 million beginning with theFebruary distribution, to $3.3 million beginning with the July distribution andto $5.1 million beginning with the October distribution. With a reduction indevelopment activity in first quarter 2006 and based on the development budgetfor 2006, the development cost deduction was lowered to $3.3 million beginningwith the January 2006 distribution. XTO Energy has advised the trustee thatthis monthly deduction is expected to be maintained at least through the March2006 distribution, but will be evaluated and revised as necessary.

 

**5.****         ****Federal Income Taxes**

 

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

 

Forfederal income tax purposes, unitholders of a grantor trust are considered toown the trust’s income and principal as though no trust were in existence. Theincome of the trust is deemed to be received or accrued by the unitholders atthe time such income is received or accrued by the trust, rather than whendistributed by the trust.

 

**6.****         ****XTO Energy Inc.**

 

XTOEnergy operates approximately 94% of the underlying properties. In computingnet proceeds, XTO Energy deducts an overhead charge for reimbursement ofadministrative expenses on the underlying properties it operates. As ofDecember 31, 2005, the overhead charge was approximately $666,000 ($532,800 netto the trust) per month and is subject to annual adjustment based on an oil andgas industry index as defined in the trust agreement.

 

Asof December 31, 2005, XTO Energy owned 54.3% of the trust. In January 2006, the Board of Directors ofXTO Energy declared a dividend of all of the 21.7 million trust units it owns. Theseunits are to be distributed on May 12, 2006 to XTO Energy’s common stockholdersof record on April 26, 2006. After this dividend, XTO Energy will not be aunitholder of the trust. XTO Energy also announced in January 2006 that it willconsider selling the underlying properties. Any sale is dependent upon XTOEnergy’s ability to structure a tax-efficient transaction and receivesufficient consideration from a buyer it deems to be qualified.

 

18

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XTOEnergy sells a significant portion of natural gas production from theunderlying properties to certain of XTO Energy’s wholly owned subsidiariesunder contracts in existence when the trust was created, generally at amountsapproximating monthly published market prices. Most of the production from theHugoton area is sold under a contract to Timberland Gathering & ProcessingCompany, Inc. (“TGPC”) based on the index price. Much of the gas production inMajor County, Oklahoma is sold to Ringwood Gathering Company (“RGC”), whichretains approximately $0.31 per Mcf compression and gathering fee. TGPC and RGCsell gas to Cross Timbers Energy Services, Inc. (“CTES”), which markets gas tothird parties. XTO Energy sells directly to CTES most gas production not solddirectly to TGPC or RGC.

 

Totalgas sales from the underlying properties to XTO Energy’s wholly ownedsubsidiaries were $107.9 million for the year ended December 31, 2005, or 54%of total gas sales, $81.7 million for the year ended December 31, 2004, or 54%of total gas sales and $76.5 million for the year ended December 31, 2003, or54% of total gas sales.

 

**7.****         ****Contingencies**

 

*Litigation*

 

OnOctober 17, 1997, an action, styled *UnitedStates of America ex rel. Grynberg v. Cross Timbers Oil Company, et al.*,was filed in the United States District Court for the Western District ofOklahoma by Jack J. Grynberg on behalf of the United States under the *qui tam* provisions of the U.S. FalseClaims Act against XTO Energy. The plaintiff alleges that XTO Energy underpaidroyalties on natural gas produced from federal leases and lands owned by NativeAmericans in amounts in excess of 20% as a result of mismeasuring the volume ofnatural gas, incorrectly analyzing its heating content and improperly valuingthe natural gas during at least the past ten years. The plaintiff seeks trebledamages 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. FalseClaims Act, and an order for XTO Energy to cease the allegedly impropermeasuring practices. This lawsuit against XTO Energy and similar lawsuits filedby Grynberg against more than 300 other companies have been consolidated in theUnited States District Court for Wyoming. In October 2002, the court granted amotion to dismiss Grynberg’s royalty valuation claims, and Grynberg’s appeal ofthis decision was dismissed for lack of appellate jurisdiction in May 2003. Theparties have completed discovery regarding whether the plaintiff has met thejurisdictional prerequisites for maintaining an action under the U.S. FalseClaims Act. In June 2004, XTO Energy joined with other defendants in filing amotion to dismiss, contending that the plaintiff has not satisfied thejurisdictional requirements to maintain this action. A hearing on this motionoccurred in March 2005, and in May 2005, the special master, who was appointedby the district judge to expedite matters and make recommendations to thedistrict judge in the case, issued a report and recommendation to dismiss thecase against some of the defendants but to retain jurisdiction of the caseinvolving XTO Energy and other defendants. XTO Energy and the other defendantsfiled motions to modify the special master’s report, requesting the districtjudge to also dismiss the case as to XTO Energy and other defendants. Thedistrict judge heard oral arguments on December 9, 2005, as to all motionsseeking adoption, modification or reversal of the special master’s report, andXTO Energy is awaiting the decision of the district court. While XTO Energy isunable to predict the outcome of this case or estimate the amount of anypossible loss, it has informed the trustee that it believes that theallegations of this lawsuit are without merit and intends to vigorously defendthe action. However, an order to change measuring practices or a relatedsettlement could adversely affect the trust by reducing net proceeds in thefuture by an amount that is presently not determinable, but, in XTO Energymanagement’s opinion, is not currently expected to be material to the trust’sannual distributable income, financial position or liquidity.

 

Certainof the underlying properties are involved in various other lawsuits and certaingovernmental proceedings arising in the ordinary course of business. XTO Energyhas advised the trustee that it does not believe that the ultimate resolutionof these claims will have a material effect on trust annual distributableincome, financial position or liquidity.

 

19

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*Other*

 

Severalstates have enacted legislation to require state income tax withholding fromnonresident recipients of oil and gas proceeds. After consultation with itsstate tax counsel, XTO Energy has advised the trustee that it believes thetrust is not subject to these withholding requirements. However, regulationsare subject to change by the various states, which could change this conclusion.In the event it is determined that the trust is required to withhold statetaxes, distributions to the unitholders would be reduced by the requiredamount, subject to the unitholder’s right to file a state tax return to claimany refund due.

 

**8.****         ****Supplemental Oil and GasReserve Information (Unaudited)**

 

Provedoil and gas reserve information is included in Item 2 of the trust’s AnnualReport on Form 10-K included in this report.

 

**9.****         ****Quarterly Financial Data(Unaudited)**

 

Thefollowing is a summary of net profits income, distributable income and distributableincome per unit by quarter for 2005 and 2004:

 
| ** **          | ** ** | ** **      | ** **      | ** **        | ** ** | **Distributable** | ** ** |
|---------------------|------------|-----------------|-----------------|-------------------|------------|-------------------|------------|
| ** **          | ** ** | **Net Profits** | ** **      | **Distributable** | ** ** | **Income**        | ** ** |
| ** **          | ** ** | **Income**      | ** **      | **Income**        | ** ** | **per Unit**      | ** ** |
| **2005**            |       |            |            |              |       |              |       |
| **First  Quarter**  | ** ** | **$**           | **25,818,940**  | ** **        | **$**      | **25,698,160**    | ** ** | **$** | **0.642454** | ** ** |
| **Second  Quarter** | ** ** | **22,965,660**  | ** **      | **22,832,040**    | ** ** | **0.570801**      | ** ** |
| **Third  Quarter**  | ** ** | **24,325,921**  | ** **      | **24,304,200**    | ** ** | **0.607605**      | ** ** |
| **Fourth  Quarter** | ** ** | **32,018,800**  | ** **      | **31,997,480**    | ** ** | **0.799937**      | ** ** |
| ** **          | ** ** | **$**           | **105,129,321** | ** **        | **$**      | **104,831,880**   | ** ** | **$** | **2.620797** |   |
| 2004                |       |            |            |              |       |              |       |
| First  Quarter      |       | $               | 19,057,231      |              | $          | 18,976,760        |       | $ | 0.474419 |   |
| Second  Quarter     |       | 18,289,557      |            | 18,178,560        |       | 0.454464          |       |
| Third  Quarter      |       | 23,521,511      |            | 23,428,840        |       | 0.585721          |       |
| Fourth  Quarter     |       | 21,051,715      |            | 21,012,760        |       | 0.525319          |       |
|                |       | $               | 81,920,014      |              | $          | 81,596,920        |       | $ | 2.039923 |   |

 

20

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**REPORT OFINDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM**

 

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

 

Wehave audited the accompanying statements of assets, liabilities and trustcorpus of the Hugoton Royalty Trust as of December 31, 2005 and 2004, and therelated statements of distributable income and changes in trust corpus for eachof the years in the three-year period ended December 31, 2005. These financialstatements are the responsibility of the trustee. Our responsibility is to expressan opinion on these financial statements based on our audits.

 

Weconducted our audits in accordance with the standards of the Public CompanyAccounting Oversight Board (United States). Those standards require that weplan and perform the audit to obtain reasonable assurance about whether thefinancial statements are free of material misstatement. An audit includesexamining, on a test basis, evidence supporting the amounts and disclosures inthe financial statements. An audit also includes assessing the accountingprinciples used and significant estimates made by the trustee, and evaluatingthe overall financial statement presentation. We believe that our auditsprovide a reasonable basis for our opinion.

 

Asdescribed in Note 2 to the financial statements, these financial statementshave been prepared on the modified cash basis of accounting, which is acomprehensive basis of accounting other than accounting principles generallyaccepted in the United States of America.

 

Inour opinion, the financial statements referred to above present fairly, in allmaterial respects, the assets, liabilities, and trust corpus of the HugotonRoyalty Trust as of December 31, 2005 and 2004 and its distributable income andchanges in trust corpus for each of the years in the three-year period endedDecember 31, 2005 in conformity with the modified cash basis of accountingdescribed in Note 2.

 

Wealso have audited, in accordance with the standards of the Public CompanyAccounting Oversight Board (United States), the effectiveness of the HugotonRoyalty Trust’s internal control over financial reporting as of December 31,2005, based on criteria established in Internal Control—Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission(COSO), and our report dated March 16, 2006 expressed an unqualified opinion onthe trustee’s assessment of, and the effective operation of, internal controlover financial reporting.

 

 

KPMG LLP

 

Dallas, TexasMarch 16, 2006

 

21

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**REPORT OFINDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM**

 

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

 

Wehave audited the trustee’s assessment, included in Trustee’s Report on InternalControl over Financial Reporting under Item 9A of the accompanying AnnualReport on Form 10-K, that Hugoton Royalty Trust maintained effective internalcontrol over financial reporting as of December 31, 2005, based on criteriaestablished in Internal Control—Integrated Framework issued by the Committee ofSponsoring Organizations of the Treadway Commission (COSO). The trustee of the HugotonRoyalty Trust is responsible for maintaining effective internal control overfinancial reporting and for its assessment of the effectiveness of internalcontrol over financial reporting. Our responsibility is to express an opinionon the trustee’s assessment and an opinion on the effectiveness of the trust’sinternal control over financial reporting based on our audit.

 

Weconducted our audit in accordance with the standards of the Public CompanyAccounting Oversight Board (United States). Those standards require that weplan and perform the audit to obtain reasonable assurance about whethereffective internal control over financial reporting was maintained in allmaterial respects. Our audit included obtaining an understanding of internalcontrol over financial reporting, evaluating the trustee’s assessment, testingand evaluating the design and operating effectiveness of internal control, andperforming such other procedures as we considered necessary in thecircumstances. We believe that our audit provides a reasonable basis for ouropinion.

 

Thetrust’s internal control over financial reporting is a process designed toprovide reasonable assurance regarding the reliability of financial reportingand the preparation of financial statements for external purposes in accordancewith the modified cash basis of accounting. The trust’s internal control overfinancial reporting includes those policies and procedures that (1) pertain tothe maintenance of records that, in reasonable detail, accurately and fairlyreflect the transactions and dispositions of the assets of the trust; (2)provide reasonable assurance that transactions are recorded as necessary topermit preparation of financial statements in accordance with the modified cashbasis of accounting, and that receipts and expenditures of the trust are beingmade only in accordance with authorizations of the trustee; and (3) providereasonable assurance regarding prevention or timely detection of unauthorizedacquisition, use, or disposition of the trust’s assets that could have amaterial effect on the financial statements.

 

Becauseof its inherent limitations, internal control over financial reporting may notprevent or detect misstatements. Also, projections of any evaluation ofeffectiveness to future periods are subject to the risk that controls maybecome inadequate because of changes in conditions, or that the degree ofcompliance with the policies or procedures may deteriorate.

 

Inour opinion, the trustee’s assessment that Hugoton Royalty Trust maintainedeffective internal control over financial reporting as of December 31, 2005, isfairly stated, in all material respects, based on criteria established inInternal Control—Integrated Framework issued by the Committee of SponsoringOrganizations of the Treadway Commission (COSO). Also, in our opinion, HugotonRoyalty Trust maintained, in all material respects, effective internal controlover financial reporting as of December 31, 2005, based on criteria establishedin Internal Control—Integrated Framework issued by the Committee of SponsoringOrganizations of the Treadway Commission (COSO).

 

Wealso have audited, in accordance with the standards of the Public CompanyAccounting Oversight Board (United States), the statements of assets,liabilities, and trust corpus of the Hugoton Royalty Trust as

 

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of December 31, 2005 and 2004, and therelated statements of distributable income and changes in trust corpus for eachof the years in the three-year period ended December 31, 2005, and our reportdated March 16, 2006 expressed an unqualified opinion on those financialstatements and included an explanatory paragraph that described the trust’smethod of accounting as explained in Note 2 to the financial statements.

 

KPMG LLP

 

Dallas, Texas

March 16, 2006

 

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**HUGOTONROYALTY TRUST**

 

901 Main Street, 17th Floor

P.O. Box 830650

Dallas, Texas 75283-0650

(877) 228-5083

Bank of America, N.A., Trustee

 

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

 

**WEB SITE**

 

www.hugotontrust.com

 

**AUDITORS**

 

KPMG LLP

Dallas, Texas

 

**LEGALCOUNSEL**

 

Thompson & Knight L.L.P.

Dallas, Texas

 

**TAX COUNSEL**

 

Winstead Sechrest & Minick P.C.

Houston, Texas

 

**TRANSFERAGENT AND REGISTRAR**

 

Mellon Investor Services, L.L.C.

www.melloninvestor.com

 

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