UNITED STATESSECURITIES AND EXCHANGE COMMISSIONWashington, D.C. 20549

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**FORM 10-K**

ANNUAL REPORT PURSUANT TO SECTION 13OR 15(d) OFTHE SECURITIES EXCHANGE ACT OF 1934

| **For the fiscal year ended December 31, 2005** | **Commission  file number 1-10476** |
|------------------------------------------------------|-------------------------------------|

 

**Hugoton Royalty Trust**

(Exact name of registrantas specified in the Hugoton Royalty Trust Indenture)

| **Texas**                                 | **58-6379215**      |
|-------------------------------------------|---------------------|
| (State or other  jurisdiction of          | (I.R.S. Employer    |
| incorporation or  organization)           | Identification No.) |
| **Bank of  America, N.A.**                | **75283-0650**      |
| **Trustee**                               | (Zip Code)          |
| **P.O. Box  830650**                 | ** **          |
| **Dallas,  Texas**                        | ** **          |
| (Address of  principal executive offices) |                |

 

Registrant’s telephonenumber including area code:  (877) 228-5083

Securities registeredpursuant to Section 12(b) of the Act:

| ** **                       | **Title of each class**      | ** ** | ** ** | **Name of each exchange on which registered** | ** ** |
|----------------------------------|------------------------------|------------|------------|-----------------------------------------------|------------|
| **Units of Beneficial Interest** | **New  York Stock Exchange** |

 

Securities registeredpursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is awell-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes* *o  No x

Indicate by check mark if the registrant is notrequired to file reports pursuant to Section 13 or Section 15(d) ofthe Act. Yes* *o  No x

Indicate by check mark whether the registrant (1) hasfiled all reports required to be filed by Section 13 or 15(d) of theSecurities Exchange Act of 1934 during the preceding 12 months (or for suchshorter period that the registrant was required to file such reports), and (2) hasbeen subject to such filing requirements for the past 90 days. Yes x  No* *o

Indicate by check mark if disclosure of delinquentfilers pursuant to Item 405 of Regulation S-K is not contained herein, and willnot be contained, to the best of registrant’s knowledge, in definitive proxy orinformation statements incorporated by reference in Part III of this Form 10-Kor any amendment to this Form 10-K. x

Indicate by check mark whether the registrant is alarge accelerated filer, an accelerated filer, or a non-accelerated filer. Seedefinition of “accelerated filer and large accelerated filer” in Rule 12b-2of the Exchange Act (check one):

Large accelerated filer* *o  Acceleratedfiler x Non-accelerated filer* *o

Indicate by check mark whether the registrant is ashell company (as defined in Exchange Act Rule 12b-2). Yes* *o  No x

The aggregate market value of the units of beneficialinterest of the trust, based on the closing price on the New York StockExchange as of June 30, 2005 (the last business day of its most recentlycompleted second fiscal quarter), held by non-affiliates of the registrant onthat date was approximately $542 million.

At February 28, 2006, there were 40,000,000 unitsof beneficial interest of the trust outstanding.

**DOCUMENTSINCORPORATED BY REFERENCE**

Listed below is the only document parts of which areincorporated herein by reference and the parts of this report into which thedocument is incorporated:

2005 Annual Reportto Unitholders—Part II

 

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**PART I**

**Item 1.**                        *Business*

Hugoton Royalty Trust is an express trust createdunder the laws of Texas pursuant to the Hugoton Royalty Trust Indenture enteredinto on December 1, 1998 between XTO Energy Inc. (formerly known as CrossTimbers Oil Company), as grantor, and NationsBank, N.A., as trustee. Bank ofAmerica, N.A., successor to NationsBank, N.A., is now the trustee of the trust.The principal office of the trust is located at 901 Main Street, Dallas, Texas75202 (telephone number 877-228-5083).

The trust’s internet web site is www.hugotontrust.com.We make available free of charge, through our web site, our Annual Report on Form 10-K,quarterly reports on Form 10-Q, current reports on Form 8-Kand all amendments to those reports filed or furnished pursuant to Section 13(a) or15(d) of the Securities Exchange Act of 1934. These reports are accessiblethrough our internet web site as soon as reasonably practicable after weelectronically file such material with, or furnish it to, the Securities andExchange Commission.

Effective December 1, 1998, XTO Energy conveyedto the trust 80% net profits interests in certain predominantly natural gasproducing working interest properties in Kansas, Oklahoma and Wyoming underthree separate conveyances. In exchange for these net profits interestconveyances to the trust, 40 million units of beneficial interest wereissued to XTO Energy. In April and May 1999, XTO Energy sold a totalof 17 million units in the trust’s initial public offering. In 1999 and 2000,XTO Energy also sold 1.3 million trust units to certain of its officers. Thetrust did not receive any proceeds from these sales of trust units. As of December 31,2005, XTO Energy owned 21,705,893 units in the trust. Units are listed andtraded on the New York Stock Exchange under the symbol “HGT.”

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 commonstockholders of record on April 26, 2006. After this dividend, XTO Energywill not be a unitholder of the trust.

The net profits interests entitle the trust to receive80% of the net proceeds from the sale of oil and gas from the underlyingproperties. Each month XTO Energy determines the amount of cash received fromthe sale of production and deducts property and production taxes, productionexpense, development costs and overhead.

Net proceeds payable to the trust depend uponproduction quantities, sales prices of oil and gas and costs to develop andproduce oil and gas in the prior month. If monthly costs exceed revenues forany of the three conveyances (one for each of the states of Kansas, Oklahomaand Wyoming), such excess costs must be recovered, with accrued interest, fromfuture net proceeds of that conveyance and cannot reduce net proceeds fromother conveyances.

The trust is not liable for any production costs orliabilities attributable to the underlying properties. If at any time the trustreceives net profits income in excess of the amount due, the trust is notobligated to return such overpayment, but net profits income payable to thetrust for the next month will be reduced by the overpayment, plus interest atthe prime rate.

As a working interest owner, XTO Energy can generallydecline participation in any operation and allow consenting parties to conductsuch operations, as provided under the operating agreements. XTO Energy alsocan assign, sell, or otherwise transfer its interest in the underlyingproperties, subject to the net profits interests, or can abandon an underlyingproperty if it is incapable of producing in paying quantities, as determined byXTO Energy.

To the extent allowed, XTO Energy is responsible formarketing its production from the underlying properties under existing salescontracts or new arrangements on the best terms reasonably obtainable in thecircumstances. See Item 2., “Pricing and Sales Information.”

Net profits incomereceived by the trust on or before the last business day of the month is relatedto net proceeds received by XTO Energy in the preceding month, and is generallyattributable to oil and gas 

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productiontwo months prior. The amount to be distributed to unitholders each month by thetrustee is determined by:

**Adding—**

(1)   net profits income received,

(2)   interest income and any other cash receiptsand

(3)   cash available as a result of reduction of cash reserves, then

**Subtracting—**

(1)   liabilities paid and

(2)   thereduction in cash available related to establishment of or increase in any cashreserve.

The monthly distribution amount is distributed tounitholders of record within ten business days after the monthly record date. Themonthly record date is generally the last business day of the month. Thetrustee calculates the monthly distribution amount and announces thedistribution per unit at least ten days prior to the monthly record date.

The trustee may establish cash reserves forcontingencies. Cash held for such reserves, as well as for pending payment ofthe monthly distribution amount, may be invested in federal obligations orcertificates of deposit of major banks.

The trustee’s function is to collect the net profitsincome from the net profits interests, to pay all trust expenses, and pay themonthly distribution amount to unitholders. The trustee’s powers are specifiedby the terms of the trust indenture. The trust cannot engage in any businessactivity or acquire any assets other than the net profits interests andspecific short-term cash investments. The trust has no employees since alladministrative functions are performed by the trustee.

Approximately 92% of thenet profits income received by the trust during 2005, as well as 94% of theestimated proved reserves of the net profits interests at December 31,2005 (based on estimated future net cash flows using year-end oil and gasprices), is attributable to natural gas. There has historically been a greaterdemand for gas during the winter months than the rest of the year. Otherwise,trust income generally is not subject to seasonal factors, nor dependent uponpatents, licenses, franchises or concessions. The trust conducts no researchactivities.

**Item 1A.**                *Risk Factors*

The following factors, among others, could causeactual results to differ materially from those contained in forward-lookingstatements made in this report and presented elsewhere by the trustee from timeto time. Such factors, among others, may have a material adverse effect uponthe trust’s financial condition, distributable income and changes in trustcorpus.

The following discussionof risk factors should be read in conjunction with the financial statements andrelated notes included in the trust’s annual report to unitholders for the yearended December 31, 2005. Because of these and other factors, past financialperformance should not be considered an indication of future performance.

***The market price for the trust units may not reflectthe value of the net profits interests held by the trust.***

The public trading pricefor the trust units tends to be tied to the recent and expected levels of cashdistributions on the trust units. The amounts available for distribution by thetrust vary in response to numerous factors outside the control of the trust orXTO Energy, including prevailing prices for oil and natural gas produced fromthe underlying properties. The market price of the trust units is notnecessarily indicative of the value that the trust would realize if the netprofits interests were sold to a third party buyer. In addition, such marketprice is not necessarily reflective of the fact that, since the assets of thetrust are depleting assets, a portion of each cash distribution paid on thetrust units should be considered by investors as a return of capital, with theremainder being considered as a return on investment. There is 

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noguarantee that distributions made to a unitholder over the life of thesedepleting assets will equal or exceed the purchase price paid by theunitholder.

***Oil and natural gas prices fluctuate due to a numberof uncontrollable factors, and any decline will adversely affect the netproceeds payable to the trust and trust distributions.***

The trust’s monthly cashdistributions are highly dependent upon the prices realized from the sale ofnatural gas and, to a lesser extent, oil. Oil and natural gas prices canfluctuate widely on a month-to-month basis in response to a variety of factorsthat are beyond the control of the trust and XTO Energy. Factors thatcontribute to price fluctuations include instability in oil-producing regions,worldwide economic conditions, weather conditions, the supply and price ofdomestic and foreign oil and natural gas, consumer demand, the price andavailability of alternative fuels, the proximity to, and capacity of,transportation facilities and the effect of worldwide energy conservationmeasures. Moreover, government regulations, such as regulation of natural gastransportation and price controls, can affect product prices in the long term. Loweroil and natural gas prices may reduce the amount of oil and natural gas that iseconomic to produce and will reduce net profits available to the trust. Thevolatility of energy prices reduces the predictability of future cashdistributions to trust unitholders.

***Higher production expense and/or development costs, withoutconcurrent increases in revenue, will directly decrease the net proceedspayable to the trust.***

Production expense anddevelopment costs are deducted in the calculation of the trust’s share of netproceeds. Accordingly, higher or lower production expense and developmentcosts, without concurrent increases in revenue, will directly decrease orincrease the amount received by the trust. If development costs and productionexpense for underlying properties in a particular state exceed the productionproceeds from the properties, the trust will not receive net proceeds for thoseproperties until future proceeds from production in that state exceed the totalof the excess costs plus accrued interest during the deficit period. Developmentactivities may not generate sufficient additional revenue to repay the costs.

***Proved reserve estimates depend on many assumptionsthat may turn out to be inaccurate. Any material inaccuracies in reserveestimates or underlying assumptions could cause the quantities and net presentvalue of the reserves to be overstated.***

Estimating proved oil andgas reserves is inherently uncertain. Petroleum engineers consider many factorsand make assumptions in estimating reserves and future net cash flows. Thosefactors and assumptions include historical production from the area comparedwith production rates from similar producing areas, the effects of governmentalregulation, assumptions about future commodity prices, production expense anddevelopment costs, taxes and capital expenditures, the availability of enhancedrecovery techniques and relationships with landowners, working interestpartners, pipeline companies and others. Lower oil and gas prices generallycause lower estimates of proved reserves. Ultimately, actual production, revenuesand expenditures for the underlying properties will vary from estimates andthose variances could be material. Because the trust owns net profitsinterests, it does not own a specific percentage of the oil and gas reserves. Estimatedproved reserves for the net profits interests are based on estimates ofreserves for the underlying properties and an allocation method that considersestimated future net proceeds and oil and gas prices. Increases or decreases inoil and gas prices directly increase or decrease estimated reserves of the netprofits interests.

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***Operational risks and hazards associated with thedevelopment of the underlying properties may decrease trust distributions.***

There are operationalrisks and hazards associated with the production and transportation of oil andnatural gas, including without limitation natural disasters, blowouts,explosions, fires, leakage of oil or natural gas, releases of other hazardousmaterials, mechanical failures, cratering, and pollution. Any of these orsimilar occurrences could result in the interruption or cessation ofoperations, personal injury or loss of life, property damage, damage toproductive formations or equipment, damage to the environment or naturalresources, or cleanup obligations. The operation of oil and gas properties isalso subject to various laws and regulations. Non-compliance with such laws andregulations could subject the operator to additional costs, sanctions orliabilities. The uninsured costs resulting from any of the above or similaroccurrences could be deducted as a production expense or development cost incalculating the net proceeds payable to the trust and would therefore reducetrust distributions by the amount of such uninsured costs.

***Trust unitholders and the trustee have no influenceover the operations on, or future development of, the underlying properties.***

Neither the trustee northe trust unitholders can influence or control the operation or futuredevelopment of the underlying properties. The failure of an operator to conductits operations or discharge its obligations in a proper manner could have anadverse effect on the net proceeds payable to the trust. Although XTO Energyand other operators of the underlying properties must adhere to the standard ofa prudent operator, they are under no obligation to continue operating theproperties. Neither the trustee nor trust unitholders have the right to replacean operator.

***The assets of the trust represent interests indepleting assets and, if XTO Energy and any other operators developing theunderlying properties do not perform additional development projects, theassets may deplete faster than expected. Eventually, the assets of the trustwill cease to produce in commercial quantities and the trust will cease toreceive proceeds from such assets.***

The net proceeds payableto the trust are derived from the sale of depleting assets. Eventually, theproperties underlying the trust’s net profits interests will cease to producein commercial quantities and the trust will, therefore, cease to receive anynet proceeds therefrom. The reduction in proved reserve quantities is a commonmeasure of the depletion. Future maintenance and development projects on theunderlying properties will affect the quantity of proved reserves. The timingand size of these projects will depend on the market prices of oil and naturalgas. If XTO Energy or other operators of the properties do not implementadditional maintenance and development projects, the future rate of productiondecline of proved reserves may be higher than the rate currently estimated.

***Terrorism and continued geopolitical hostilities couldadversely affect trust distributions or the market price of the trust units.***

Terrorist attacks and thethreat of terrorist attacks, whether domestic or foreign, as well as themilitary or other actions taken in response, cause instability in the globalfinancial and energy markets. Terrorism and other geopolitical hostilitiescould adversely affect trust distributions or the market price of the trustunits in unpredictable ways, including through the disruption of fuel suppliesand markets, increased volatility in oil and natural gas prices, or thepossibility that the infrastructure on which the operators of the underlyingproperties rely could be a direct target or an indirect casualty of an act ofterror.

***XTO Energy may transfer its interest in theunderlying  properties without theconsent of the trust or the trust unitholders.***

XTO Energy may at any time transfer all or part of itsinterest in the underlying properties to another party. Neither the trust northe trust unitholders are entitled to vote on any transfer of the properties 

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underlying the trust’s netprofits interests, and the trust will not receive any proceeds of any suchtransfer. Following any transfer, the transferred property will continue to besubject to the net profits interests of the trust, but the calculation,reporting and remitting of net proceeds to the trust will be the responsibilityof the transferee.

In January 2006, XTOEnergy announced that it will consider selling the underlying properties. Anysale is dependent upon XTO Energy’s ability to structure a tax-efficienttransaction and receive sufficient consideration from a buyer it deems to bequalified. If XTO Energy sells the underlying properties, future developmentplans, as described in Item 2. below, may not be pursued by the transferee.

***XTO Energy or any other operator of any underlyingproperty may abandon the property, thereby terminating the related net profitsinterest payable to the trust.***

XTO Energy or any otheroperator of the underlying properties, or any transferee thereof, may abandonany well or property without the consent of the trust or the trust unitholdersif they reasonably believe that the well or property can no longer produce incommercially economic quantities. This could result in the termination of thenet profits interest relating to the abandoned well or property.

***The net profits interests can be sold and the trustwould be terminated.***

The trust may sell the netprofits interests if the holders of 80% or more of the trust units approve thesale or vote to terminate the trust. The trust will terminate if it fails togenerate gross proceeds from the underlying properties of at least$1,000,000 per year over any consecutive two-year period. Sale of all ofthe net profits interests will terminate the trust. The net proceeds of anysale must be for cash with the proceeds promptly distributed to the trustunitholders.

***Trust unitholders have limited voting rights and havelimited ability to enforce the trust’s rights against XTO Energy or any otheroperators of the underlying properties.***

The voting rights of a trust unitholder are morelimited than those of stockholders of most public corporations. For example,there is no requirement for annual meetings of trust unitholders or for anannual or other periodic re-election of the trustee. Additionally, trustunitholders have no voting rights in XTO Energy.

The trust indenture andrelated trust law permit the trustee and the trust to sue XTO Energy or anyother operators of the underlying properties to compel them to fulfill theterms of the conveyance of the net profits interests. If the trustee does nottake appropriate action to enforce provisions of the conveyance, the recourseof the trust unitholders would likely be limited to bringing a lawsuit againstthe trustee to compel the trustee to take specified actions. Trust unitholdersprobably would not be able to sue XTO Energy or any other operators of theunderlying properties.

***Financial information of the trust is not prepared inaccordance with GAAP.***

The financial statementsof the trust are prepared on a modified cash basis of accounting, which is acomprehensive basis of accounting other than accounting principles generallyaccepted in the U.S., or GAAP. Although this basis of accounting is permittedfor royalty trusts by the Securities and Exchange Commission, the financialstatements of the trust differ from GAAP financial statements because netprofits income is not accrued in the month of production, expenses are notrecognized when incurred and cash reserves may be established for certaincontingencies that would not be recorded in GAAP financial statements.

***The limited liability of trust unitholders isuncertain.***

The trust unitholders arenot protected from the liabilities of the trust to the same extent that ashareholder would be protected from a corporation’s liabilities. The structureof the trust does not include 

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theinterposition of a limited liability entity such as a corporation or limitedpartnership which would provide further limited liability protection to trustunitholders. While the trustee is liable for any excess liabilities incurred ifthe trustee fails to insure that such liabilities are to be satisfied only outof trust assets, under the laws of Texas, which are unsettled on this point, aunitholder may be jointly and severally liable for any liability of the trustif the satisfaction of such liability was not contractually limited to theassets of the trust and the assets of the trust and the trustee are notadequate to satisfy such liability. As a result, trust unitholders may beexposed to personal liability. The trust, however, is not liable for productioncosts or other liabilities of the underlying properties.

***Drilling oil and natural gas wells is a high-riskactivity and subjects the trust to a variety of factors that it cannot control.***

Drilling oil andnatural gas wells involves numerous risks, including the risk that commerciallyproductive oil and natural gas reservoirs are not encountered. The presence ofunanticipated pressures or irregularities in formations, miscalculations oraccidents may cause drilling activities to be unsuccessful. In addition, thereis often uncertainty as to the future cost or timing of drilling, completingand operating wells. Further, development activities may be curtailed, delayedor canceled as a result of a variety of factors, including:

·       unexpected drillingconditions;

·       titleproblems;

·       restrictedaccess to land for drilling or laying pipeline;

·       pressureor irregularities in formations;

·       equipmentfailures or accidents;

·       adverseweather conditions; and

·       costsof, or shortages or delays in the availability of, drilling rigs, tubularmaterials and equipment.

While these risks do notexpose the trust to liabilities of the driller or operator of the well, theycan reduce net proceeds payable to the trust and trust distributions bydecreasing oil and gas revenues or increasing production expense or developmentcosts from the underlying properties. Furthermore, these risks may cause thecosts of development activities on the underlying properties to exceed therevenues therefrom, thereby reducing net proceeds payable to the trust andtrust distributions.

***The underlying properties are subject to complexfederal, state and local laws and regulations that could adversely affect netproceeds payable to the trust and trust distributions.***

Extensive federal, stateand local regulation of the oil and natural gas industry significantly affectsoperations on the underlying properties. In particular, oil and natural gasdevelopment and production are subject to stringent environmental regulations.These regulations have increased the costs of planning, designing, drilling,installing, operating and abandoning oil and natural gas wells and otherrelated facilities, which costs could reduce net proceeds payable to the trustand trust distributions. These regulations may become more demanding in thefuture.

**Item 1B.**               *Unresolved Staff Comments*

As of December 31,2005, the trust did not have any unresolved Securities and Exchange Commissionstaff comments.

**Item 2.**                        *Properties*

The net profits interests are the principal asset ofthe trust. The trustee cannot acquire any other assets, with the exception ofcertain short-term investments as specified under Item 1. The trustee may sell 

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or otherwise dispose ofall or any part of the net profits interests if approved by at least 80% of theunitholders, or upon termination of the trust. Otherwise, the trust may onlysell 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 underlyingproperties. Any such sale must be for cash with the proceeds promptlydistributed to the unitholders. The underlying properties are predominantlynatural gas producing leases located in the states of Kansas, Oklahoma andWyoming. The principal productive areas are the Hugoton area, Anadarko Basinand Green River Basin.

All the underlying properties are currently owned byXTO Energy. XTO Energy may sell all or any portion of the underlying propertiesat any time, subject to and burdened by the net profits interests. In January 2006,XTO Energy announced that it will consider selling the underlying properties.Any sale is dependent upon XTO Energy’s ability to structure a tax-efficienttransaction and receive sufficient consideration from a buyer it deems to bequalified.

Statements below regarding2006 development plans assume that XTO Energy will continue to own and operatethe underlying properties.

**Hugoton Area**

Natural gas was discovered in the Hugoton area in 1922.With an estimated five million productive acres covering parts of Texas,Oklahoma and Kansas, the Hugoton area is one of the largest domestic naturalgas producing areas. During 2005, sales volumes from the underlying propertiesin the Hugoton area averaged approximately 25,300 Mcf of gas and 86 Bbls of oilper day.

Most of the production from the underlying propertiesin the Hugoton area 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 that underlie the 79,500 net acres held by production by the Chaseformation wells, including the Council Grove between 2,950 and 3,400 feet, theMorrow between 6,000 and 6,300 feet, the Chester between 6,350 and 6,700 feetand the St. Louis between 7,500 and 8,000 feet. Since 2003, XTO Energy hasdrilled successful wells to these formations and plans to continue thisdevelopment program in 2006. XTO Energy has participated in 3-D seismicshoots covering 30,000 acres of XTO Energy’s net acreage position beneath theChase formation.

In 2005, XTO Energy successfully drilled four gross(3.2 net) wells in the Hugoton area and continued its restimulation program inthe Chase intervals, completing 55 of these restimulations. XTO Energy hasinformed the trustee that it plans to drill up to ten wells and perform 50Chase restimulations during 2006. Some of the Chase restimulations involveadding perforations in a tighter interval of the formation that was previouslybypassed.

XTO Energy’s futuredevelopment plans for the underlying properties in the Hugoton area include:

·       additionalcompression to lower line pressures,

·       pumpingunit installations,

·       openingnew producing zones in existing wells,

·       drillingadditional wells,

·       drillingdeeper in existing wells to new producing zones, and

·       restimulatingproducing intervals in existing wells utilizing new technology.

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XTO Energy delivers most of its Hugoton gas productionto a gathering and processing system operated by a subsidiary. This systemcollects approximately 60% of its throughput from underlying properties, which,in recent months, has been approximately 16,200 Mcf per day from 264 wells. Thegathering subsidiary purchases the gas from XTO Energy at the wellhead, gathersand transports the gas to its plant, and treats and processes the gas at theplant. The gathering subsidiary pays XTO Energy for wellhead volumes at a priceof 80% to 85% of the net residue price received by XTO Energy’s marketingaffiliate. This affiliate currently sells the residue to a pipeline at a pricebased on the monthly pipeline index less $0.03 per MMBtu.

Other Hugoton gasproduction is sold under a third party contract. Under the contract, XTO Energyreceives 74.5% of the net proceeds received from the sale of the residue gasand liquids.

**Anadarko Basin**

Oil and gas were discovered in the Anadarko Basin ofwestern Oklahoma in 1945. Daily sales volumes from the underlying properties inthe Anadarko Basin averaged 34,200 Mcf of gas and 766 Bbls of oil in 2005. XTOEnergy is one of the largest producers in the Ringwood, Northwest Okeene andCheyenne Valley fields in Major County, the principal producing region of theunderlying properties in the Anadarko Basin.

The fields in the Major County area are characterizedby oil and gas production from a variety of structural and stratigraphic traps.Productive zones range from 6,500 to 9,400 feet and include the Oswego, RedFork, Inola, Chester, Manning, Mississippian, Hunton and Arbuckle formations.

In Major and Woodward counties, the Mississippian(Osage), Chester and Red Fork formations were the primary drilling targets in2005. In Major County, XTO Energy successfully drilled ten gross (6.5 net)wells and performed nine workovers. XTO Energy has informed the trustee that itplans to drill up to 13 wells and perform up to 15 workovers in Major Countyduring 2006. The most significant increase in 2005 new well production occurredin Woodward County, where 12 gross (11.3 net) wells were successfully drilledand completed in the Chester formation and four workovers were performed. During2006, XTO Energy has informed the trustee that it plans to drill up to tenwells and perform up to eight workovers in Woodward County.

XTO Energy plans tofurther develop the underlying properties in the Major County area primarilythrough:

·       mechanicalstimulation of existing wells,

·       installingartificial lift,

·       openingnew producing zones in existing wells,

·       deepeningexisting wells to new producing zones, and

·       drillingadditional wells.

A gathering subsidiary of XTO Energy operates a 300-milegathering system and pipeline in the Major County area. The gathering subsidiaryand a third-party processor purchase natural gas produced at the wellhead fromXTO Energy and other producers in the area under various agreements includinglife-of-production contracts. The gathering subsidiary gathers and transportsthe gas to a third-party processor, which processes the gas and pays XTO Energyand other producers for at least 50% of the liquids processed. After the gas isprocessed, the gathering subsidiary transports the gas via a residue pipelineto a connection with an interstate pipeline. The gathering subsidiary sells theresidue gas to the marketing subsidiary of XTO Energy based upon a publishedindex price. The gathering subsidiary pays this price to XTO Energy less acompression and gathering fee of approximately $0.31 per Mcf of residue gas. Thisgathering fee was previously approved by the Federal Energy RegulatoryCommission when the gathering subsidiary was regulated. During 2005, thegathering system collected approximately 15,000 Mcf per day 

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from over 400 wells, approximately70% of which XTO Energy operates. Estimated capacity of the gathering system is35,000 Mcf per day. The gathering subsidiary also provides contract operatingservices to properties in Woodward County, collecting approximately 11,500 Mcfper day from 92 wells, for an average fee of approximately $0.10 per Mcf.

XTO Energy also sells gasdirectly to its marketing subsidiary, which then sells the gas to third parties.The price paid to XTO Energy is based upon the average price of severalpublished indices, but does not include a deduction for any marketing fees. Theprice paid by the marketing affiliate includes a deduction for anytransportation fees charged by the third party.

**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 inthe early 1970s. The producing reservoirs are the Cretaceous-aged Frontier,Baxter and Dakota sandstones at depths ranging from 7,500 to 10,000 feet.

Daily 2005 sales volumes from the underlyingproperties in the Fontenelle Field averaged 22,700 Mcf of natural gas and 39Bbls of oil. In 2005, XTO Energy successfully drilled seven gross (seven net)wells and performed ten workovers. XTO Energy has advised the trustee that it plansto perform up to ten workovers and may drill up to ten wells in the Green RiverBasin during 2006. XTO Energy also plans to further test reduction in pipelinepressure which has recently shown potential for increasing production in theFontenelle Field.

Potentialdevelopment activities for the underlying properties in this area include:

·       installingartificial lift,

·       restimulatingproducing intervals utilizing new technology,

·       additionalcompression to lower line pressures,

·       openingnew producing zones in existing wells, and

·       drillingadditional wells.

XTO Energy markets the gasproduced from the Fontenelle Unit and nearby properties under three differentmarketing arrangements. Under the agreement covering approximately 70% of thegas sold, XTO Energy compresses the gas on the lease, transports it off thelease and compresses the gas again prior to entry into the gas plant pipeline. Thepipeline transports the gas 35 miles to the gas plant, where the gas isprocessed, then redelivered to XTO Energy and sold to XTO Energy’s marketingsubsidiary. The owner of the gas plant and related pipeline charges XTO Energyfor operational fuel and processing. In 2005, the fuel charge was 0.3% of thevolumes produced and the processing fee was $0.055 per MMBtu. The marketingsubsidiary then sells the residue gas to third parties based upon a spot salesprice and pays the net sales proceeds to XTO Energy. The marketing subsidiarydoes not receive a marketing fee. The gas not sold under the above arrangementis sold either under a similar arrangement where the fee is $0.16 per MMBtu, orunder a contract where XTO Energy directly sells the gas to a third party onthe lease at an adjusted index price. Condensate is sold at the lease to anindependent third party at market rates.

**Producing Acreage and Well Counts**

For the following data, “gross” refers to the totalwells or acres on the underlying properties in which XTO Energy owns a workinginterest and “net” refers to gross wells or acres multiplied by the percentageworking interest owned by XTO Energy. Although many of XTO Energy’s wellsproduce both oil and gas, a well is categorized as an oil well or a gas wellbased upon the ratio of oil to natural gas production.

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The underlying propertiesare interests in developed properties located primarily in gas producingregions of Kansas, Oklahoma and Wyoming. The following is a summary of theapproximate producing acreage of the underlying properties at December 31,2005. Undeveloped acreage is not significant.

| ** **        | ** ** | **Gross** | ** ** | **Net** | ** ** |
|-------------------|------------|-----------|------------|---------|------------|
| Hugoton Area      |       | 216,790   |       | 199,590 |       |
| Anadarko Basin    |       | 152,042   |       | 113,946 |       |
| Green River Basin |       | 39,155    |       | 26,899  |       |
| Total             |       | 407,987   |       | 340,435 |       |

 

The following is a summaryof the producing wells on the underlying properties as of December 31,2005:

| ** ** | ** ** | **Operated  Wells** | ** ** | **Nonoperated  Wells** | ** ** | **Total** | ** ** |
|------------|------------|---------------------|------------|------------------------|------------|-----------|------------|
| ** ** | ** ** | **Gross**           | ** ** | **Net**                | ** ** | **Gross** | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** |
| Gas        |       | 1,185               |       | 1,065.6                |       |      | 269        |   |   | 62.7 |   | 1,454 |   | 1,128.3 |   |
| Oil        |       | 46                  |       | 41.2                   |       |      | 6          |   |   | 1.7 |   | 52 |   | 42.9 |   |
| Total      |       | 1,231               |       | 1,106.8                |       |      | 275        |   |   | 64.4 |   | 1,506 |   | 1,171.2 |   |

 

The following is a summaryof the number of wells drilled on the underlying properties during the yearsindicated. Unless otherwise indicated, all wells drilled are developmental. Therewere 11 gross (7.2 net) wells in process of drilling at December 31, 2005.

| ** **                      | ** ** | **2005**  | ** ** | **2004** | ** ** | **2003**  | ** ** |
|---------------------------------|------------|-----------|------------|----------|------------|-----------|------------|
| ** **                      | ** ** | **Gross** | ** ** | **Net**  | ** ** | **Gross** | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** |
| Completed gas  wells* (a)* |       |      | 41         |     |       | 29.2      |       |   | 25 |   |   | 19.2 |   |   | 23 |   |   | 18.4 |   |
| Completed oil  wells            |       |      | 1          |     |       | 1.0       |       |   | — |   |   | — |   |   | — |   |   | — |   |
| Non-productive  wells           |       |      | 1          |     |       | 0.5       |       |   | 4 |   |   | 1.5 |   |   | — |   |   | — |   |
| Total                           |       |      | 43         |     |       | 30.7      |       |   | 29 |   |   | 20.7 |   |   | 23 |   |   | 18.4 |   |

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*(a)**            *Included in completed gas wells are wells drilled on nonoperatedinterests totaling nine gross (1.9 net) in 2005, four gross (0.6 net) in 2004and two gross (0.7 net) in 2003.

10

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**Oil and Natural Gas Production**

Trust production isrecognized in the period net profits income is received, which is the monthfollowing receipt by XTO Energy, and generally two months after the time ofproduction. Oil and gas production and average sales prices attributable to theunderlying properties and the net profits interests for the three years ended December 31,2005 were as follows:

| ** **               | ** ** | **2005**    | ** ** | **2004**    | ** ** | **2003**    | ** ** |
|--------------------------|------------|-------------|------------|-------------|------------|-------------|------------|
| **Production**           |       |        |       |        |       |        |       |
| *Underlying Properties*  |       |        |       |        |       |        |       |
| Gas—Sales (Mcf)     |       | 29,986,698  |       | 30,238,663  |       | 31,490,564  |       |
| Average per day (Mcf)    |       | 82,155      |       | 82,619      |       | 86,276      |       |
| Oil—Sales (Bbls)    |       | 325,193     |       | 318,694     |       | 331,867     |       |
| Average per day (Bbls)   |       | 891         |       | 871         |       | 909         |       |
| *Net  Profits Interests* |       |        |       |        |       |        |       |
| Gas—Sales (Mcf)     |       | 15,836,681  |       | 16,462,378  |       | 17,832,189  |       |
| Average per day (Mcf)    |       | 43,388      |       | 44,979      |       | 48,855      |       |
| Oil—Sales (Bbls)    |       | 177,980     |       | 184,487     |       | 196,005     |       |
| Average per day (Bbls)   |       | 488         |       | 504         |       | 537         |       |
| **Average  Sales Price** |       |        |       |        |       |        |       |
| Gas (per Mcf)            |       | $ 6.64 |       | $ 4.99 |       | $ 4.54 |       |
| Oil (per Bbl)            |       | $52.27      |       | $38.11      |       | $30.13      |       |

 

**Oil and Natural Gas Reserves**

***General***

Miller and Lents, Ltd., independent petroleumengineers, has estimated oil and gas reserves attributable to the underlyingproperties as of December 31, 2005, 2004, 2003 and 2002. The estimatedreserves for the underlying properties are then used by XTO Energy to calculatethe estimated oil and gas reserves attributable to the net profits interests. Numerousuncertainties are inherent in estimating reserve volumes and values, and suchestimates are subject to change as additional information becomes available. Thereserves actually recovered and the timing of production of these reserves maybe substantially different from the original estimates.

Reserve quantities and revenues for the net profitsinterests were estimated from projections of reserves and revenues attributableto the combined interests of the trust and XTO Energy in the subject properties.Since the trust has defined net profits interests, the trust does not own aspecific percentage of the oil and gas reserve quantities. Accordingly,reserves allocated to the trust pertaining to its 80% net profits interests inthe properties have effectively been reduced to reflect recovery of the trust’s80% portion of applicable production and development costs. Because trustreserve quantities are determined using an allocation formula, any fluctuationsin actual or assumed prices or costs will result in revisions to the estimatedreserve quantities allocated to the net profits interests.

The standardized measure of discounted future net cashflows and changes in such discounted cash flows as presented below are preparedusing assumptions required by the Financial Accounting Standards Board. Theseassumptions include the use of year-end prices for oil and gas and year-endcosts for estimated future development and production expenditures to producethe proved reserves. Because natural gas prices are influenced by seasonaldemand, use of year-end prices, as required by the Financial AccountingStandards Board, may not be the most representative in estimating futurerevenues or reserve data. Future net cash flows are discounted at an annualrate of 10%. No provision is included for federal income taxes since future netcash flows are not subject to taxation at the trust level.

11

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Estimated costs to plug and abandon wells on theunderlying properties at the end of their productive lives have not beendeducted from cash flows since this is not a legal obligation of the trust. Thesecosts are the legal obligation of XTO Energy as the owner of the underlyingworking interests and will only be deducted from net proceeds payable to thetrust if net proceeds from the related conveyance exceed such costs when paid,subject to excess cost carryforward provisions as described under Item 1.

Because overhead costs are deducted in the calculationof net proceeds, the standardized measure for the underlying properties and netprofits interests has been reduced by estimated overhead costs, resulting in arestatement from previously reported amounts of the standardized measure at December 31,2004, 2003 and 2002. The proved reserves for the net profits interests havealso been restated from previously reported amounts due to a reduction inreserves allocated to the net profits interests to reflect recovery of 80% ofestimated overhead costs.

Year-end weighted averagerealized gas prices used to determine the standardized measure were $8.72 perMcf in 2005, $5.68 per Mcf in 2004, $5.76 per Mcf in 2003 and $4.37 per Mcf in2002. Year-end oil prices used to determine the standardized measure were basedon a West Texas Intermediate crude oil posted price of $57.75 per Bbl in 2005,$40.25 per Bbl in 2004, $29.25 per Bbl in 2003 and $28.00 per Bbl in 2002.

***Proved Reserves***

| ***(in thousands)***             | ** ** | **Underlying  Properties**                         | ** ** | **Net Profits Interests**                 | ** ** |
|---------------------------------------|------------|----------------------------------------------------|------------|-----------------------------------------------------|------------|
| ** **                            | ** ** | **Gas     (Mcf)   ** | ** ** | **Oil     (Bbls)   ** | ** ** | **Gas     (Mcf)   ** | ** ** | **Oil     (Bbls)   ** | ** ** |
| Balance, December 31,  2002      |       | 476,501                                            |       |                                                | 4,111      |   |   | 265,043 |   |   | 2,304 |   |   |
| Extensions, additions and discoveries |       | 10,008                                             |       |                                                | —     |   |   | 5,752 |   |   | — |   |   |
| Revisions of prior estimates          |       | 7,310                                              |       |                                                | (10        | ) |   | 25,820 |   |   | 179 |   |   |
| Production—sales volumes         |       | (31,491                                            | )          |                                                | (332       | ) |   | (17,832 | ) |   | (196 | ) |   |
| Balance, December 31, 2003       |       | 462,328                                            |       |                                                | 3,769      |   |   | 278,783 |   |   | 2,287 |   |   |
| Extensions, additions and discoveries |       | 16,905                                             |       |                                                | 228        |   |   | 9,676 |   |   | 131 |   |   |
| Revisions of prior estimates          |       | (5,061                                             | )          |                                                | 115        |   |   | (17,404 | ) |   | 35 |   |   |
| Production—sales volumes         |       | (30,239                                            | )          |                                                | (319       | ) |   | (16,462 | ) |   | (184 | ) |   |
| Balance, December 31, 2004       |       | 443,933                                            |       |                                                | 3,793      |   |   | 254,593 |   |   | 2,269 |   |   |
| Extensions, additions and discoveries |       | 24,806                                             |       |                                                | 146        |   |   | 14,273 |   |   | 84 |   |   |
| Revisions of prior estimates          |       | 4,292                                              |       |                                                | 167        |   |   | 18,902 |   |   | 258 |   |   |
| Production—sales volumes         |       | (29,987                                            | )          |                                                | (325       | ) |   | (15,837 | ) |   | (178 | ) |   |
| Balance,  December 31, 2005      |       | 443,044                                            |       |                                                | 3,781      |   |   | 271,931 |   |   | 2,433 |   |   |

 

Extensions, additions and discoveries in 2003, 2004and 2005 are primarily related to delineation of additional proved undevelopedreserves in the Anadarko Basin. Revisions of prior estimates of the proved gasreserves for the underlying properties in each year are primarily because ofchanges in the year-end gas and oil prices. Higher upward and downwardrevisions for the net profits interests as compared with the underlyingproperties in each year were caused by changes in year-end oil and gas priceswhich resulted in an increase or decrease in gas reserves allocated to thetrust.

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***Proved DevelopedReserves***

| ***(in thousands)*** | ** ** | **Underlying  Properties** | ** ** | **Net Profits  Interests** | ** ** |
|---------------------------|------------|----------------------------|------------|---------------------------------|------------|
| ** **                | ** ** | **Gas  (Mcf)**             | ** ** | **Oil  (Bbls)**                 | ** ** | **Gas  (Mcf)** | ** ** | **Oil  (Bbls)** | ** ** |
| December 31, 2002    |       | 407,959                    |       | 3,580                           |       | 231,034 |   | 2,034 |   |
| December 31, 2003    |       | 396,847                    |       | 3,294                           |       | 241,636 |   | 2,013 |   |
| December 31, 2004    |       | 381,768                    |       | 3,308                           |       | 220,426 |   | 1,993 |   |
| December 31,  2005   |       | 379,527                    |       | 3,361                           |       | 235,470 |   | 2,180 |   |

 

***StandardizedMeasure of Discounted Future Net Cash Flows from Proved Reserves***

| ***(in thousands)***    | ** ** | **December 31** | ** ** |
|------------------------------|------------|----------------------|------------|
| ** **                   | ** ** | **2005**             | ** ** | **2004** | ** ** | **2003** | ** ** |
| ***Underlying  Properties*** |       |                 |       |   |   |   |   |
| Future cash  inflows         |       | $                    | 4,092,655  |   | $ | 2,680,376 |   | $ | 2,793,090 |   |
| Future costs:                |       |                 |       |   |   |   |   |
| Production                   |       | 1,109,882            |       | 856,280 |   | 824,460 |   |
| Development                  |       | 80,610               |       | 57,059 |   | 52,779 |   |
| Future net cash  flows       |       | 2,902,163            |       | 1,767,037 |   | 1,915,851 |   |
| 10% discount  factor         |       | 1,511,732            |       | 895,304 |   | 990,039 |   |
| Standardized measure         |       | $                    | 1,390,431  |   | $ | 871,733 |   | $ | 925,812 |   |
| ***Net  Profits Interests*** |       |                 |       |   |   |   |   |
| Future cash  inflows         |       | $                    | 2,515,738  |   | $ | 1,539,521 |   | $ | 1,684,953 |   |
| Future production  taxes     |       | 194,008              |       | 125,891 |   | 152,272 |   |
| Future net cash  flows       |       | 2,321,730            |       | 1,413,630 |   | 1,532,681 |   |
| 10% discount  factor         |       | 1,209,385            |       | 716,244 |   | 792,031 |   |
| Standardized  measure        |       | $                    | 1,112,345  |   | $ | 697,386 |   | $ | 740,650 |   |

 

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***Changes inStandardized Measure of Discounted Future Net Cash Flows from Proved Reserves***

| ***(in thousands)***                                              | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
|------------------------------------------------------------------------|------------|------------|------------|------------|------------|------------|------------|
| ** **                                                             | ** ** | **2005**   | ** ** | **2004**   | ** ** | **2003**   | ** ** |
| ***Underlying  Properties***                                           |       |       |       |       |       |       |       |
| Standardized  measure, January 1                                  |       | $          | 871,733    |       | $          | 925,812    |       | $ | 691,947 |   |
| Revisions:                                                             |       |       |       |       |       |       |       |
| Prices and costs                                                       |       | 566,014    |       | (36,596    | )          | 258,791    |       |
| Quantity estimates                                                     |       | 5,744      |       | (7,115     | )          | 7,879      |       |
| Accretion of discount                                                  |       | 75,570     |       | 79,856     |       | 59,730     |       |
| Future development costs                                               |       | (56,072    | )          | (22,304    | )          | (7,150     | )          |
| Production rates and other                                             |       | (92        | )          | (176       | )          | 158        |       |
| Net revisions                                                          |       | 591,164    |       | 13,665     |       | 319,408    |       |
| Extensions,  additions and discoveries                                 |       | 58,946     |       | 34,656     |       | 15,317     |       |
| Production                                                             |       | (170,612   | )          | (123,700   | )          | (113,809   | )          |
| Development costs                                                      |       | 39,200     |       | 21,300     |       | 12,949     |       |
| Net change                                                             |       | 518,698    |       | (54,079    | )          | 233,865    |       |
| Standardized measure, December 31                                 |       | $          | 1,390,431  |       | $          | 871,733    |       | $ | 925,812 |   |
| ***Net  Profits Interests***                                           |       |       |       |       |       |       |       |
| Standardized  measure, January 1                                  |       | $          | 697,386    |       | $          | 740,650    |       | $ | 553,557 |   |
| Extensions,  additions and discoveries                                 |       | 47,157     |       | 27,724     |       | 12,254     |       |
| Accretion of  discount                                                 |       | 60,456     |       | 63,885     |       | 47,784     |       |
| Revisions of  prior estimates, changes in price and other* **(a)* |       | 412,475    |       | (52,953    | )          | 207,743    |       |
| Net profits  income                                                    |       | (105,129   | )          | (81,920    | )          | (80,688    | )          |
| Standardized  measure, December 31                                |       | $          | 1,112,345  |       | $          | 697,386    |       | $ | 740,650 |   |

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*(a)**            *Revisions were primarily caused by the changes in year-end gas and oilprices and projected costs.

**Regulation**

*Natural GasRegulation*

The interstatetransportation and sale for resale of natural gas is subject to federalregulation, including transportation rates charged, storage tariffs and variousother matters, by the Federal Energy Regulatory Commission. Federal pricecontrols on wellhead sales of domestic natural gas terminated on January 1,1993. On August 8, 2005, Congress enacted the Energy Policy Act of 2005. TheEnergy Policy Act, among other things, amended the Natural Gas Act to prohibitmarket manipulation by any entity, to direct FERC to facilitate markettransparency in the market for sale or transportation of physical natural gasin interstate commerce, and to significantly increase the penalties forviolations of the Natural Gas Act, the Natural Gas Policy Act of 1978, or FERCrules, regulations or orders thereunder. While natural gas prices are currentlyunregulated, Congress historically has been active in the area of natural gasregulation. It is impossible to predict whether new legislation to regulatenatural gas might be proposed, what proposals, if any, might actually beenacted, and what effect, if any, such proposals might have on the operationsof the underlying properties.

*EnvironmentalRegulation*

Companies that are engagedin the oil and gas industry are affected by federal, state and local lawsregulating the discharge of materials into the environment. Those laws mayimpact operations of the underlying properties. No material expenses have beenincurred on the underlying properties in complying with environmental laws andregulations. XTO Energy does not expect that future compliance will have amaterial adverse effect on the trust.

14

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*State Regulation*

The various statesregulate the production and sale of oil and natural gas, including imposingrequirements for obtaining drilling permits, the method of developing newfields, the spacing and operation of wells and the prevention of waste of oiland gas resources. The rates of production may be regulated and the maximumdaily production allowables from both oil and gas wells may be established on amarket demand or conservation basis, or both.

*State Income TaxWithholding*

Several states haveenacted legislation to require state income tax withholding from nonresidentrecipients of oil and gas proceeds. After consultation with its state taxcounsel, XTO Energy has advised the trustee that it believes the trust is notsubject to these withholding requirements. However, regulations are subject tochange by the various states, which could change this conclusion. In the eventit is determined that the trust is 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 anyrefund due.

*Other Regulation*

The Minerals Management Service of the United StatesDepartment of the Interior amended the crude oil valuation regulations in July 2004and the natural gas valuation regulations in June 2005 for oil and naturalgas produced from federal oil and natural gas leases. The principal effect ofthe oil regulations pertains to which published market prices are mostappropriate to value crude oil not sold in an arm’s-length transaction and whattransportation deductions should be allowed. The principal effect of thenatural gas valuation regulations pertains to the calculation of transportationdeductions and changes necessitated by judicial decisions since the regulationswere last amended. Seven percent of the net acres of the underlying properties,primarily located in Wyoming, involve federal leases. Neither of these changeshave had a significant effect on trust distributions.

The petroleum industry isalso subject to compliance with various other federal, state and localregulations and laws, including, but not limited to, regulations and lawsrelating to environmental protection, occupational safety, resourceconservation and equal employment opportunity. XTO Energy has advised thetrustee that it does not believe that compliance with these laws will have anymaterial adverse effect upon the unitholders.

**Pricing and Sales Information**

A subsidiary of XTO Energypurchases most of XTO Energy’s natural gas production at a monthly publishedindex price, then sells the gas to third parties for the best available price. Anymarketing gains or losses are not included in trust net proceeds. Oilproduction is generally marketed at the wellhead to third parties at the bestavailable price. XTO Energy arranges for some of its natural gas to beprocessed by unaffiliated third parties and markets the natural gas liquids. Thenatural gas attributable to the underlying properties is marketed undercontracts existing at trust inception. Contracts covering production from theRingwood area of the Major County area are generally for the life of the lease,and the contract for the majority of production from the Hugoton area wasextended through 2007. If new contracts are entered with unaffiliated thirdparties, the proceeds from sales under those new contracts will be included ingross proceeds from the underlying properties. If new contracts are enteredwith XTO Energy’s marketing subsidiary, it may charge XTO Energy a fee that maynot exceed 2% of the sales price of the oil and natural gas received fromunaffiliated parties. The sales price is net of any deductions fortransportation from the wellhead to the unaffiliated parties and any gravity orquality adjustments.

15

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**Item 3.**                        LegalProceedings

On October 17, 1997, an action, styled *United States of America ex rel. Grynberg v. CrossTimbers Oil Company, et al.*, was filed in the United States DistrictCourt for the Western District of Oklahoma by Jack J. Grynberg on behalf of theUnited States under the *qui tam*provisions of the U.S. False Claims Act against XTO Energy. The plaintiffalleges that XTO Energy underpaid royalties on natural gas produced fromfederal leases and lands owned by Native Americans in amounts in excess of 20%as a result of mismeasuring the volume of natural gas, incorrectly analyzingits heating content and improperly valuing the natural gas during at least thepast ten years. The plaintiff seeks treble damages for the unpaid royalties(with interest, attorney’s fees and expenses), civil penalties between $5,000and $10,000 for each violation of the U.S. False Claims Act, and an order forXTO Energy to cease the allegedly improper measuring practices. This lawsuitagainst XTO Energy and similar lawsuits filed by Grynberg against more than 300other companies have been consolidated in the United States District Court forWyoming. In October 2002, the court granted a motion to dismiss Grynberg’sroyalty valuation claims, and Grynberg’s appeal of this decision was dismissedfor lack of appellate jurisdiction in May 2003. The parties have completeddiscovery regarding whether the plaintiff has met the jurisdictionalprerequisites for maintaining an action under the U.S. False Claims Act. In June 2004,XTO Energy joined with other defendants in filing a motion to dismiss,contending that the plaintiff has not satisfied the jurisdictional requirementsto maintain this action. Ahearing on this motion occurred in March 2005, and in May 2005, thespecial master, who was appointed by the district judge to expedite matters andmake recommendations to the district judge in the case, issued a report andrecommendation to dismiss the case against some of the defendants but to retainjurisdiction of the case involving XTO Energy and other defendants. XTO Energyand the other defendants filed motions to modify the special master’s report,requesting the district judge to also dismiss the case as to XTO Energy andother defendants. The district judge heard oral arguments on December 9,2005, as to all motions seeking adoption, modification or reversal of thespecial master’s report, and XTO Energy is awaiting the decision of thedistrict court. While XTO Energy is unable to predict the outcome ofthis case or estimate the amount of any possible loss, it has informed thetrustee that it believes that the allegations of this lawsuit are without meritand intends to vigorously defend the action. However, an order to changemeasuring practices or a related settlement could adversely affect the trust byreducing net proceeds in the future by an amount that is presently notdeterminable, but, in XTO Energy management’s opinion, is not currentlyexpected to be material to the trust’s annual distributable income, financialposition or liquidity.

Certain of the underlyingproperties are involved in various other lawsuits and certain governmentalproceedings arising in the ordinary course of business. XTO Energy has advisedthe trustee that it does not believe that the ultimate resolution of theseclaims will have a material effect on trust annual distributable income,financial position or liquidity.

**Item 4.**                        *Submission of Matters to a Vote of Security Holders*

No matters were submitted to a vote of unitholdersduring 2005.

16

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**PART II**

**Item 5.**                        *Market for Units of the Trust, Related Security Holder Matters andTrust Purchases of Units*

The section entitled “Units of Beneficial Interest” inthe trust’s annual report to unitholders for the year ended December 31,2005 is incorporated herein by reference.

The trust has no equitycompensation plans, nor has it purchased any units during the period covered bythis report.

**Item 6.**                        *Selected Financial Data*

| ** **                     | ** ** | **Year Ended December 31** | ** **  |
|--------------------------------|------------|-------------------------------------------|-------------|
| ** **                     | ** ** | **2005**                                  | ** **  | **2004** | ** ** | **2003** | ** ** | **2002** | ** ** | **2001** | ** ** |
| Net Profits  Income            |       | $                                         | 105,129,321 |   | $ | 81,920,014 |   | $ | 80,687,778 |   | $ | 29,934,195 |   | $ | 79,272,395 |   |
| Distributable  Income          |       | 104,831,880                               |        | 81,596,920 |   | 80,373,120 |   | 29,572,360 |   | 79,131,040 |   |
| Distributable  Income per Unit |       | 2.620797                                  |        | 2.039923 |   | 2.009328 |   | 0.739309 |   | 1.978276 |   |
| Distributions per  Unit        |       | 2.620797                                  |        | 2.039923 |   | 2.009328 |   | 0.739309 |   | 1.978276 |   |
| Total Assets at Year-End       |       | 185,459,610                               |        | 189,499,334 |   | 198,952,087 |   | 208,721,083 |   | 217,127,992 |   |
|                                |            |                                           |             |  |  |  |  |  |  |  |  |  |  |  |  |  |

 

**Item 7.**                        *Management’s Discussion and Analysis of Financial Condition and Resultsof Operations*

The “Trustee’s Discussionand Analysis” of financial condition and results of operations for each of theyears in the three-year period ended December 31, 2005 in the trust’sannual report to unitholders for the year ended December 31, 2005 isincorporated herein by reference.

**Liquidity and Capital Resources**

The trust’s only cash requirement is the monthlydistribution of its income to unitholders, which is funded by the monthlyreceipt of net profits income after payment of trust administration expenses. Thetrust is not liable for any production costs or liabilities attributable to theunderlying properties. If at any time the trust receives net profits income inexcess of the amount due, the trust is not obligated to return suchoverpayment, but future net profits income payable to the trust will be reducedby the overpayment, plus interest at the prime rate.

The trust does not haveany transactions, arrangements or other relationships with unconsolidatedentities or persons that could materially affect the trust’s liquidity or theavailability of capital resources.

**Off-Balance Sheet Arrangements**

The trust has nooff-balance sheet financing arrangements. The trust has not guaranteed the debtof any other party, nor does the trust have any other arrangements orrelationships with other entities that could potentially result inunconsolidated debt, losses or contingent obligations.

**Contractual Obligations**

Asshown below, the trust had no obligations and commitments to make futurecontractual payments as of December 31, 2005, other than the December distributionpayable to unitholders in January 2006, as reflected in the statement ofassets, liabilities and trust corpus.

| ** **                           | ** ** | **Payments due by Period** | ** ** |
|--------------------------------------|------------|-------------------------------------------|------------|
| ** **                           | ** ** | **Total**                                 | ** ** | **Less than  1 Year** | ** ** | **1-3 Years** | ** ** | **3-5 Years** | ** ** | **More than  5 Years** | ** ** |
| Distribution  payable to unitholders |       | $                                         | 13,524,280 |   | $ | 13,524,280 |   |   | $ | — |   |   |   | $ | — |   |   |   | $ | — |   |   |
|                                      |            |                                           |            |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |

 

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**Related Party Transactions**

The underlying properties from which the net profitsinterests were carved are currently owned by XTO Energy, which operates approximately94% of the underlying properties. In computing net proceeds, XTO Energy deductsa monthly overhead charge for reimbursement of administrative expenses on theunderlying properties it operates. As of December 31, 2005, the monthlyoverhead charge, based on the number of operated wells, was approximately$666,000 ($532,800 net to the trust) and is subject to annual adjustment basedon an oil and gas industry index.

As of December 31, 2005, XTO Energy owned21,705,893, or 54.3%, of the 40,000,000 outstanding units. In January 2006,the Board of Directors of XTO Energy declared a dividend of all of the 21.7million trust units it owns. These units are to be distributed on May 12,2006 to XTO Energy’s common stockholders of record on April 26, 2006. Afterthis dividend, XTO Energy will not be a unitholder of the trust. Also in January 2006,XTO Energy announced that it will consider selling the underlying properties. Anysale is dependent upon XTO Energy’s ability to structure a tax-efficienttransaction and receive sufficient consideration from a buyer it deems to bequalified.

XTO Energy sells asignificant portion of natural gas production from the underlying properties tocertain of XTO Energy’s wholly owned subsidiaries under contracts in existencewhen the trust was created, generally at amounts approximating monthlypublished market prices. For further information regarding natural gas salesfrom the underlying properties to affiliates of XTO Energy, see Item 2,Properties, and Note 6 to Financial Statements in the trust’s annual report tounitholders for the year ended December 31, 2005. Total gas sales from theunderlying properties to XTO Energy’s wholly owned subsidiaries were $107.9million, or 54% of total gas sales, for the year ended December 31, 2005,$81.7 million, or 54% of total gas sales, for the year ended December 31,2004 and $76.5 million, or 54% of total gas sales, for the year ended December 31,2003.

**Critical Accounting Policies**

The financial statementsof the trust are significantly affected by its basis of accounting andestimates related to its oil and gas properties and proved reserves, assummarized below.

*Basis of Accounting*

The trust’sfinancial statements are prepared on a modified cash basis, which is acomprehensive basis of accounting other than U.S. generally accepted accountingprinciples. This method of accounting is consistent with reporting of taxableincome to trust unitholders. The most significant differences between the trust’sfinancial statements and those prepared in accordance with U.S. generallyaccepted accounting principles are:

·       Netprofits income is recognized in the month received rather than accrued in themonth of production.

·       Expensesare recognized when paid rather than when incurred.

·       Cashreserves may be established by the trustee for certain contingencies that wouldnot be recorded under generally accepted accounting principles.

This comprehensive basis of accounting other than U.S.generally accepted accounting principles corresponds to the accountingpermitted for royalty trusts by the U.S. Securities and Exchange Commission, asspecified by Staff Accounting Bulletin Topic 12:E, Financial Statements ofRoyalty Trusts. For further information regarding the trust’s basis ofaccounting, see Note 2 to Financial Statements in the trust’s annual report tounitholders for the year ended December 31, 2005.

All amounts included inthe trust’s financial statements are based on cash amounts received ordisbursed, or on the carrying value of the net profits interests, which wasderived from the historical cost of the interests at the date of their transferfrom XTO Energy, less accumulated amortization to date. 

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Accordingly,there are no fair value estimates included in the financial statements based oneither exchange or nonexchange trade values.

*Oil and GasReserves*

The proved oil and gas reserves for the underlyingproperties are estimated by independent petroleum engineers. The estimatedreserves for the underlying properties are then used by XTO Energy to calculatethe estimated oil and gas reserves attributable to the net profits interests. Reserveengineering is a subjective process that is dependent upon the quality ofavailable data and the interpretation thereof. Estimates by different engineersoften vary, sometimes significantly. In addition, physical factors such as theresults of drilling, testing and production subsequent to the date of anestimate, as well as economic factors such as changes in product prices, mayjustify revision of such estimates. Because proved reserves are required to beestimated using prices at the date of the evaluation, estimated reservequantities can be significantly impacted by changes in product prices. Accordingly,oil and gas quantities ultimately recovered and the timing of production may besubstantially different from original estimates.

The standardized measureof discounted future net cash flows and changes in such cash flows, as reportedin Item 2, is prepared using assumptions required by the Financial AccountingStandards Board and the Securities and Exchange Commission. Such assumptionsinclude using year-end oil and gas prices and year-end costs for estimatedfuture development and production expenditures. Discounted future net cashflows are calculated using a 10% rate. Changes in any of these assumptions,including consideration of other factors, could have a significant impact onthe standardized measure. Accordingly, the standardized measure does notrepresent XTO Energy’s or the trustee’s estimated current market value ofproved reserves.

**Forward-Looking Statements**

Certain informationincluded in this annual report and other materials filed, or to be filed, bythe trust with the Securities and Exchange Commission (as well as informationincluded in oral statements or other written statements made or to be made byXTO Energy or the trustee) contain forward-looking statements within themeaning of Section 21E of the Securities Exchange Act of 1934, as amended,and Section 27A of the Securities Act of 1933, as amended, relating to thetrust, operations of the underlying properties and the oil and gas industry. Suchforward-looking statements may concern, among other things, developmentactivities, increased density drilling, maintenance projects, development,production and other costs, oil and gas prices, pricing differentials, provedreserves, production levels, litigation, regulatory matters and competition. Suchforward-looking statements are based on XTO Energy’s current plans,expectations, assumptions, projections and estimates and are identified bywords such as “expects,” “intends,” “plans,” “projects,” “anticipates,” “predicts,”“believes,” “goals,” “estimates,” “should,” “could”, and similar words thatconvey the uncertainty of future events. These statements are not guarantees offuture performance and involve certain risks, uncertainties and assumptionsthat are difficult to predict. Therefore, actual results may differ materiallyfrom expectations, estimates or assumptions expressed in, implied in, orforecasted in such forward-looking statements. Some of the risk factors thatcould cause actual results to differ materially are explained in Item 1A.

**Item 7A.**                *Quantitative and Qualitative Disclosures about Market Risk*

The only assets of andsources of income to the trust are the net profits interests, which generallyentitle the trust to receive a share of the net profits from oil and gasproduction from the underlying properties. Consequently, the trust is exposedto market risk from fluctuations in oil and gas prices. The trust is a passiveentity and, other than the trust’s ability to periodically borrow money asnecessary to pay expenses, liabilities and obligations of the trust that cannotbe paid out of cash held by the trust, the trust is prohibited from engaging inborrowing transactions. The amount of any such borrowings is unlikely to bematerial to the trust. In addition, the trustee is prohibited by the trustindenture from engaging in any business activity or causing the trust to enterinto any investments other than investing cash on hand in 

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specificshort-term cash investments. Therefore, the trust cannot hold any derivativefinancial instruments. As a result of the limited nature of the trust’sborrowing and investing activities, the trust is not subject to any materialinterest rate market risk. Additionally, any gains or losses from any hedgingactivities conducted by XTO Energy are specifically excluded from thecalculation of net proceeds due the trust under the forms of the conveyances. Thetrust does not engage in transactions in foreign currencies which could exposethe trust to any foreign currency related market risk.

**Item 8.**                        *Financial Statements and Supplementary Data*

The financial statementsof the trust and the notes thereto, together with the related reports of KPMGLLP dated March 16, 2006, appearing in the trust’s annual report tounitholders for the year ended December 31, 2005, are incorporated hereinby reference.

**Item 9.**                        *Changes in and Disagreements with Accountants on Accounting andFinancial Disclosure*

There have been no changesin accountants and no disagreements with the trust’s independent registeredpublic accountants on any matter of accounting principles or practices orfinancial statement disclosures during the two years ended December 31,2005.

**Item 9A.**                *Controls and Procedures*

*ConclusionRegarding the Effectiveness of Disclosure Controls and Procedures*

The trustee conducted anevaluation of the trust’s disclosure controls and procedures, as such term isdefined under Rule 13a-15(e) promulgated under the SecuritiesExchange Act of 1934, as amended. Based on this evaluation, the trustee hasconcluded that the trust’s disclosure controls and procedures were effective asof the end of the period covered by this annual report. In its evaluation ofdisclosure controls and procedures, the trustee has relied, to the extentconsidered reasonable, on information provided by XTO Energy.

*Trustee’s Report onInternal Control Over Financial Reporting*

The trustee, Bank of America, N.A., is responsible forestablishing and maintaining adequate internal control over financialreporting, as such term is defined in Rule 13a-15(f) promulgatedunder the Securities Exchange Act of 1934, as amended. The trustee conducted anevaluation of the effectiveness of the trust’s internal control over financialreporting based on the criteria established in *InternalControl—Integrated Framework* issued by the Committee of SponsoringOrganizations of the Treadway Commission. Based on the trustee’s evaluationunder the framework in *Internal Control—IntegratedFramework*, the trustee concluded that the trust’s internal controlover financial reporting was effective as of December 31, 2005. Thetrustee’s assessment of the effectiveness of the trust’s internal control overfinancial reporting as of December 31, 2005 has been audited by KPMG LLP,an independent registered public accounting firm, as stated in their report inthe trust’s annual report to unitholders for the year ended December 31,2005 which is incorporated herein by reference.

There were no changes inthe trust’s internal control over financial reporting during the quarter ended December 31,2005 that have materially affected, or are reasonably likely to materiallyaffect, the trust’s internal control over financial reporting.

**Item 9B.**               *Other Information*

None.

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**PART III**

**Item 10.**                 *Directors and Executive Officers of the Registrant*

The trust has no directors, executive officers oraudit committee. The trustee is a corporate trustee which may be removed, withor without cause, by the affirmative vote of the holders of a majority of allthe units then outstanding.

Section 16(a) of the Securities Exchange Actof 1934 requires that beneficial owners of more than 10% of the registrant’sequity securities file initial reports of beneficial ownership and reports ofchanges in beneficial ownership with the Securities and Exchange Commission andthe New York Stock Exchange. The Securities and Exchange Commission has takenthe position that executive officers and directors of XTO Energy must also fileinitial ownership reports and reports of changes in beneficial ownership. Copiesof the reports must be provided to the trust. To the trustee’s knowledge, basedsolely on the information furnished to the trust, the trust is unaware of anyperson that failed to file on a timely basis reports required by Section 16(a) filingrequirements with respect to the trust units of beneficial interest during andfor the year ended December 31, 2005.

Because the trust has noemployees, it does not have a code of ethics. Employees of the trustee, Bank ofAmerica, N.A., must comply with the bank’s code of ethics, a copy of which willbe provided to unitholders, without charge, upon request by appointment at Bankof America Plaza, 17th Floor, 901 Main Street, Dallas, Texas 75202.

**Item 11.**                 *Executive Compensation*

Thetrustee received the following annual compensation from 2003 through 2005 asspecified in the trust indenture:

| ** **                                         | ** ** | ** **                                                           | ** ** | **Other Annual**                                                                 | ** ** |
|----------------------------------------------------|------------|----------------------------------------------------------------------|------------|---------------------------------------------------------------------------------------|------------|
| **Name and Principal Position**     | ** ** | **     Year     ** | ** ** | **     Compensation (1)     ** | ** ** |
| Bank of America, N.A., Trustee |       |                                                                 | 2005       |                                                                                  |       |   | $ | 35,000 |   |   |
|                                               |       |                                                                 | 2004       |                                                                                  |       |   | 35,000 |   |   |
|                                               |       |                                                                 | 2003       |                                                                                  |       |   | 35,000 |   |   |

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(1)             Under the trust indenture, the trustee isentitled to an annual administrative fee, paid in equal monthly installments. Suchfee can be adjusted annually based on an oil and gas industry index. Upontermination of the trust, the trustee is entitled to a termination fee of$15,000.

**Item 12.**                 *Security Ownership of Certain Beneficial Owners and Management*

The trust has noequity compensation plans.

(a)   *SecurityOwnership of Certain Beneficial Owners.*The following table setsforth as of February 28, 2006 information with respect to each personknown to the trustee to beneficially own more than 5% of the outstanding unitsof the trust:

|                                | ** ** | **Amount and Nature of** | ** ** | **Percent**       | ** ** | **                          ** | ** ** |
|--------------------------------|------------|-----------------------------------------|------------|-------------------|------------|------------------------------------------------------------------------------------------------------------------------------------------------------------------|------------|
| **Name and Address** | ** ** | **Beneficial Ownership**           | ** ** | **of Class** | ** ** | ** **                                                                                                                                                       | ** ** |
| XTO Energy Inc.                |       | 21,705,893 units (1)                    |       |              | 54.3%      |                                                                                                                                                             |       |   |   |
| 810 Houston Street             |       |                                    |       |              |       |                                                                                                                                                             |       |   |   |
| Fort Worth, Texas 76102        |       |                                    |       |              |       |                                                                                                                                                             |       |   |   |

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(1)             XTO Energy has the sole power to vote and dispose ofthese units. See Part II, Item 7, “Related Party Transactions.”

(b)   *Security Ownership of Management.*Thetrust has no directors or executive officers. As of February 16, 2006,Bank of America, N.A. owned, in various fiduciary capacities, 69,999 units,with a shared right to vote 19,445 of these units and no right to vote 50,554of these units. Bank of America, N.A. 

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disclaims any beneficialinterests in these units. The number of units reflected in this paragraphincludes units held by all branches of Bank of America, N.A.

(c)   *Changes in Control.*Thetrustee knows of no arrangements which may subsequently result in a change incontrol of the trust.

**Item 13.**                 *Certain Relationships and Related Transactions*

In computing net profits income paid to the trust forthe net profits interests, XTO Energy deducts an overhead charge forreimbursement of administrative expenses of operating the underlying properties.This charge at December 31, 2005 was approximately $666,000 per month, or$7,992,000 annually (net to the trust of $532,800 per month or $6,393,600annually), and is subject to annual adjustment based on an oil and gas industryindex as defined in the trust agreement.

XTO Energy sells a significant portion of natural gasproduction from the underlying properties to certain of its wholly ownedsubsidiaries under contracts in existence when the trust was created, generallyat amounts approximating monthly published prices. For further information, see“Hugoton Area,” “Anadarko Basin,” “Green River Basin” and “Pricing and SalesInformation,” of Item 2.

See Item 11 for theremuneration received by the trustee from 2003 through 2005 and Item 12(b) forinformation concerning units owned by the trustee, Bank of America, N.A., invarious fiduciary capacities.

**Item 14.**                 *Principal Accounting Fees and Services*

Feesfor services performed by KPMG LLP for the years ended December 31, 2005and 2004:

| ** **          | ** ** | **2005** | ** ** | **2004** | ** ** |
|---------------------|------------|----------|------------|----------|------------|
| Audit fees          |       | $        | 66,000     |     | $          | 76,206 |   |
| Audit-related  fees |       | —   |       | —   |       |
| Tax fees            |       | —   |       | —   |       |
| All other fees      |       | —   |       | —   |       |
|                |       | $        | 66,000     |     | $          | 76,206 |   |

 

As referenced in Item 10, above, the trust has noaudit committee, and as a result, has no audit committee pre-approval policywith respect to fees paid to KPMG LLP.

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**PART IV**

**Item 15.**                 *Exhibits and Financial Statement Schedules*

(a)           The following documentsare filed as a part of this report:

1.                *Financial Statements (incorporated by reference in Item 8 of thisreport)*

Independent RegisteredPublic Accounting Firm Reports

Statementsof Assets, Liabilities and Trust Corpus at December 31, 2005 and 2004

Statementsof Distributable Income for the years ended December 31, 2005, 2004 and2003

Statementsof Changes in Trust Corpus for the years ended December 31, 2005, 2004 and2003

Notes to Financial Statements

2.                *Financial Statement Schedules*

Financial statement schedules are omitted because ofthe absence of conditions under which they are required or because the requiredinformation is given in the financial statements or notes thereto.

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3.                *Exhibits*

|  (4) |   | (a)    |   | Hugoton Royalty Trust Indenture by and between  NationsBank, N.A. (now Bank of America, N.A.), as trustee, and Cross Timbers  Oil Company (predecessor of XTO Energy) heretofore filed as Exhibit 4.1  to the trust’s Registration Statement No. 333-68441 on Form S-1  filed with the Securities and Exchange Commission on December 4, 1998,  is incorporated herein by reference.                                                                                          |   |
|-----------|--------|--------|--------|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|--------|
|      |   | (b)    |   | Net Overriding Royalty Conveyance (Hugoton Royalty  Trust, 80%—Kansas) as amended and restated from Cross Timbers Oil Company  (predecessor of XTO Energy) to NationsBank, N.A. (now Bank of America, N.A.),  as trustee, dated December 1, 1998, heretofore filed as  Exhibit 10.1.1 to the trust’s Registration Statement No. 333-68441  on Form S-1 filed with the Securities and Exchange Commission on  March 16, 1999, is incorporated herein by reference.   |   |
|      |   | (c)    |   | Net Overriding Royalty Conveyance (Hugoton Royalty  Trust, 80%—Oklahoma) as amended and restated from Cross Timbers Oil Company  (predecessor of XTO Energy) to NationsBank, N.A. (now Bank of America, N.A.),  as trustee, dated December 1, 1998, heretofore filed as  Exhibit 10.1.2 to the trust’s Registration Statement No. 333-68441  on Form S-1 filed with the Securities and Exchange Commission on  March 16, 1999, is incorporated herein by reference. |   |
|      |   | (d)    |   | Net Overriding Royalty Conveyance (Hugoton Royalty  Trust, 80%—Wyoming) as amended and restated from Cross Timbers Oil Company  (predecessor of XTO Energy) to NationsBank, N.A. (now Bank of America, N.A.),  as trustee, dated December 1, 1998, heretofore filed as  Exhibit 10.1.3 to the trust’s Registration Statement No. 333-68441  on Form S-1 filed with the Securities and Exchange Commission on  March 16, 1999, is incorporated herein by reference.  |   |
| (13)      |   |   |   | Hugoton Royalty Trust  annual report to unitholders for the year ended December 31, 2005                                                                                                                                                                                                                                                                                                                                                                                                          |   |
| (23.1)    |   |   |   | Consent of KPMG LLP                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    |   |
| (23.2)    |   |   |   | Consent of Miller and Lents, Ltd.                                                                                                                                                                                                                                                                                                                                                                                                                                                                      |   |
| (31)      |   |   |   | Rule 13a-14(a)/15d-14(a) Certification                                                                                                                                                                                                                                                                                                                                                                                                                                                       |   |
| (32)      |   |   |   | Section 1350  Certification                                                                                                                                                                                                                                                                                                                                                                                                                                                                       |   |

 

Copies of the above Exhibits are available to anyunitholder, at the actual cost of reproduction, upon written request to thetrustee, Bank of America, N.A., P.O. Box 830650, Dallas, Texas 75283-0650.

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**SIGNATURES**

Pursuantto the requirements of Section 13 or 15(d) of the Securities ExchangeAct of 1934, the Registrant has duly caused this Report to be signed on itsbehalf by the undersigned thereunto duly authorized.

|                            |   | HUGOTON ROYALTY TRUST             |
|----------------------------|--------|-----------------------------------|
|                       |   | By BANK OF AMERICA, N.A., TRUSTEE |
|                       |   | By                                |   | /s/  NANCY G. WILLIS |
|                       |   | * *                          |   | Nancy G. Willis*Vice President* |
|                       |   | XTO ENERGY INC.                   |
| Date: March 16,  2006 |   | By                                |   | /s/  LOUIS G. BALDWIN |
|                       |   | * *                          |   | Louis G. Baldwin*Executive Vice President and  Chief Financial Officer* |

 

(The trust has nodirectors or executive officers.)

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