UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, 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, 2006** |   | **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  incorporation or organization) |   | (I.R.S. Employer  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 theregistrant is a well-known seasoned issuer, as defined in Rule 405 of theSecurities Act. Yes**x  No o 

Indicate by check mark ifthe registrant is not required to file reports pursuant to Section 13 or Section 15(d) ofthe Act. Yes* *o No  x

Indicate by check markwhether the registrant (1) has filed all reports required to be filed by Section 13or 15(d) of the Securities Exchange Act of 1934 during the preceding 12months (or for such shorter period that the registrant was required to filesuch reports), and (2) has been subject to such filing requirements forthe past 90 days. Yes x  No  o

Indicate by check mark ifdisclosure of delinquent filers pursuant to Item 405 of Regulation S-K is notcontained herein, and will not be contained, to the best of registrant’sknowledge, in definitive proxy or information statements incorporated byreference in Part III of this Form 10-K or any amendment tothis Form 10-K. o

Indicate by check markwhether the registrant is a large accelerated filer, an accelerated filer, or anon-accelerated filer. See definition of “accelerated filer and largeaccelerated filer” in Rule 12b-2 of the Exchange Act (check one):

Large accelerated filer x  Acceleratedfiler o Non-accelerated filer o

Indicate by check markwhether the registrant is a shell company (as defined in Exchange Act Rule 12b-2).Yes o No x

The aggregate market valueof the units of beneficial interest of the trust, based on the closing price onthe New York Stock Exchange as of June 30, 2006 (the last business day ofits most recently completed second fiscal quarter), held by non-affiliates ofthe registrant on that date was approximately $1.15 billion.

At February 28, 2007,there were 40,000,000 units of beneficial interest of the trust outstanding.

**DOCUMENTSINCORPORATED BY REFERENCE**

Listed below is the onlydocument parts of which are incorporated herein by reference and the parts ofthis report into which the document is incorporated:

2006 Annual Report to 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  Cross Timbers Oil Company), as grantor, andNationsBank, N.A., as trustee. Bank of America, N.A., successor to NationsBank,N.A., is now the trustee of the trust. The principal office of the trust islocated at 901 Main Street, Dallas, Texas 75202 (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. Units arelisted and traded on the New York Stock Exchange under the symbol “HGT.”

In May 2006, XTO Energy distributed all of itsremaining 21.7 million trust units as a dividend to its common stockholders. XTOEnergy currently is not 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 upon productionquantities, sales prices of oil and gas and costs to develop and produce oiland gas in the prior month. If monthly costs exceed revenues for any of thethree conveyances (one for each of the states of Kansas, Oklahoma and Wyoming),such excess costs must be recovered, with accrued interest, from future netproceeds of that conveyance and cannot reduce net proceeds from otherconveyances.

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.”

Netprofits income received by the trust on or before the last business day of themonth is related to net proceeds received by XTO Energy in the preceding month,and is generally attributable to oil and gas 

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production two months prior. The amount to bedistributed to unitholders each month by the trustee 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 91% of thenet profits income received by the trust during 2006, as well as 91% of theestimated proved reserves of the net profits interests at December 31,2006 (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, 2006. Because of these and other factors, pastfinancial performance should not be considered an indication of futureperformance.

***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 

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byinvestors as a return of capital, with the remainder being considered as areturn on investment. There is no guarantee that distributions made to aunitholder over the life of these depleting assets will equal or exceed thepurchase price paid by the unitholder.

***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,without concurrent increases in revenue, will directly decrease the netproceeds payable 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 changes 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,revenues and expenditures for the underlying properties will vary fromestimates and those variances could be material. Because the trust owns netprofits interests, it does not own a specific percentage of the oil and gasreserves. Estimated proved reserves for the net profits interests are based onestimates of reserves for the underlying properties and an allocation methodthat considers estimated future net proceeds and oil and gas prices. Increasesor decreases in oil and gas prices directly increase or decrease estimatedreserves of the net profits interests.

***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 

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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 in depletingassets and, if XTO Energy and any other operators developing the underlyingproperties do not perform additional successful 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. In addition, a reduction in depletion taxbenefits may reduce the market value of the trust units.***

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 successful development projects, the future rate ofproduction decline of proved reserves may be higher than the rate currentlyestimated.

***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 supplies andmarkets, increased volatility in oil and natural gas prices, or the possibilitythat the infrastructure on which the operators of the underlying propertiesrely could be a direct target or an indirect casualty of an act of terror.

***XTO Energy may transfer its interest in the underlyingproperties without the consent of the trust or the trust unitholders.***

XTO Energy may at any timetransfer all or part of its interest in the underlying properties to anotherparty. Neither the trust nor the trust unitholders are entitled to vote on anytransfer of the properties underlying the trust’s net profits interests, andthe trust will not receive any proceeds of any such transfer. Following anytransfer, the transferred property will continue to be subject to the net profitsinterests of the trust, but the calculation, reporting and remitting of netproceeds to the trust will be the responsibility of the transferee.

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***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 trust wouldbe 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 the interposition of a limited liability entitysuch as a corporation or limited partnership which would provide furtherlimited liability protection to trust unitholders. While the trustee is liablefor any excess liabilities incurred if the trustee fails to insure that suchliabilities are to be satisfied only out of trust assets, under the laws ofTexas, which are unsettled on this point, a unitholder may be jointly andseverally liable for any liability of the trust if the satisfaction of suchliability was not contractually limited to the assets of the trust and theassets of the trust and the trustee are not adequate to satisfy such liability.As a result, trust unitholders may be exposed to personal liability. The trust,however, is not liable for production costs or other liabilities of theunderlying properties.

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***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:

·       unexpecteddrilling conditions;

·       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 drilling contractor or operator of thewell, they can reduce net proceeds payable to the trust and trust distributionsby decreasing oil and gas revenues or increasing production expense ordevelopment costs from the underlying properties. Furthermore, these risks maycause the costs of development activities on the underlying properties toexceed the revenues therefrom, thereby reducing net proceeds payable to thetrust and trust 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*.****               UnresolvedStaff Comments*

As of December 31,2006, 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 sellor otherwise dispose of all or any part of the net profits interests ifapproved by at least 80% of the unitholders, or upon termination of the trust.Otherwise, the trust may only sell up to 1% of the value of the net profitsinterests in any calendar year, pursuant to notice from XTO Energy of itsdesire to sell the related underlying properties. Any such sale must be forcash with the proceeds promptly distributed to the unitholders. The underlyingproperties are predominantly natural gas producing leases located in the statesof Kansas, Oklahoma and Wyoming. The principal productive areas are the Hugotonarea, Anadarko Basin and Green River Basin.

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All the underlyingproperties are currently owned by XTO Energy. XTO Energy may sell all or anyportion of the underlying properties at any time, subject to and burdened bythe net profits interests. In January 2006, XTO Energy announced that itwould consider selling the underlying properties. However, XTO Energy advisedthe trustee in August 2006, that after a full review, it has decided toretain ownership of these underlying property interests at this time.

**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 2006, daily sales volumes from the underlyingproperties in the Hugoton area averaged approximately 23,600 Mcf of gas and 74Bbls of oil.

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, which range from 2,950 to 8,000 feet and include the CouncilGrove, Morrow, Chester and St. Louis formations. These formations arecharacterized by both oil and gas production from a variety of structural andstratigraphic traps. Since 2003, XTO Energy has drilled successful wells tothese formations and plans to continue this development program in 2007. XTOEnergy has participated in 3-D seismic shoots covering 30,000 acres of XTOEnergy’s net acreage position beneath the Chase formation.

Within this area, XTO Energy successfully drilledthree gross (3.0 net) wells and performed 29 workovers in 2006, of which20 were Chase restimulations. XTO Energy has informed the trustee that it plansto drill up to five wells and perform up to 30 workovers during 2007.

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

·       additionalcompression to lower line pressures,

·       installingartificial lift,

·       openingnew producing zones in existing wells,

·       restimulatingproducing intervals in existing wells utilizing new technology,

·       deepeningexisting wells to new producing zones, and

·       drillingadditional wells.

XTO Energy delivers most of its Hugoton gas productionto a gathering and processing system operated by a subsidiary. This systemcollects approximately 70% of its throughput from underlying properties, which,in recent months, has been approximately 16,950 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 $0.01 per MMBtu.

Other Hugoton gas productionis sold under a third party contract. Under the contract, XTO Energy receives74.5% of the net proceeds received from the sale of the residue gas andliquids.

**Anadarko Basin**

Oil and gas accumulations were discovered in theAnadarko Basin of western Oklahoma in 1945. XTO Energy is one of the largestproducers in the Ringwood, Northwest Okeene and Cheyenne Valley fields of MajorCounty, the Northeast Cedardale field of Woodward County and the Elk City fieldof Beckham County, the principal producing regions of the underlying propertiesin the Anadarko Basin. 

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Daily sales volumes fromthe underlying properties in the Anadarko Basin averaged 34,800 Mcf of gas and799 Bbls of oil in 2006.

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. Withinthis area, XTO Energy successfully drilled 12 gross (8.0 net) wells andperformed 12 workovers in 2006. XTO Energy has informed the trustee that itplans to drill up to 12 wells and perform up to 15 workovers in Major Countyduring 2007.

The fields within Woodward County are characterizedprimarily by gas production from a variety of structural and stratigraphictraps. Productive zones range from 6,000 to 7,500 feet and include the CottageGrove, Oswego, Chester and Mississippian formations. Within this area, XTOEnergy successfully drilled 12 gross (10.4 net) wells and performed fiveworkovers in 2006. XTO Energy has informed the trustee that it plans to drillup to 11 wells and perform up to eight workovers in Woodward County during2007.

The Elk City field on the eastern edge of BeckhamCounty produces oil and gas from a structural anticline with stratigraphictrapping features. Production zones range from 9,500 to 15,500 feet and includethe Hoxbar, Atoka and Morrow formations. Within this area, XTO Energysuccessfully drilled two gross (1.8 net) wells and performed threeworkovers in 2006. XTO Energy has informed the trustee that it plans to drillup to four wells and perform up to six workovers within the Elk City fieldduring 2007.

XTO Energy plans tofurther develop the underlying properties in the Anadarko Basin 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 a300-mile gathering system and pipeline in the Major County area. The gatheringsubsidiary and a third-party processor purchase natural gas produced at thewellhead from XTO Energy and other producers in the area under variousagreements including life-of-production contracts. The gatheringsubsidiary gathers and transports the gas to a third-party processor, whichprocesses the gas and pays XTO Energy and other producers for at least 50% ofthe liquids processed. After the gas is processed, the gathering subsidiarytransports the gas via a residue pipeline to a connection with an interstatepipeline. The gathering subsidiary sells the residue gas to the marketingsubsidiary of XTO Energy based upon a published index price. The gatheringsubsidiary pays this price to XTO Energy less a compression and gathering feeof approximately $0.31 per Mcf of residue gas. This gathering fee waspreviously approved by the Federal Energy Regulatory Commission when thegathering subsidiary was regulated. During 2006, the gathering system collectedapproximately 13,500 Mcf per day from over 400 wells, approximately 52% ofwhich XTO Energy operates. Estimated capacity of the gathering system is 28,000Mcf per day. The gathering subsidiary also provides contract operating servicesto properties in Woodward County, collecting approximately 10,500 Mcf per dayfrom 107 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.

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**Green River Basin**

The Green River Basin is located in southwesternWyoming. Natural gas was discovered in the Fontenelle Field of the Green RiverBasin in the early 1970s. The producing reservoirs are the Cretaceous-agedFrontier, Baxter and Dakota sandstones at depths ranging from 7,500 to 10,000feet.

Daily 2006 sales volumes from the underlyingproperties in the Fontenelle Field averaged 22,800 Mcf of natural gas and 38Bbls of oil. In 2006, XTO Energy successfully drilled eight gross (8.0 net)wells and performed ten workovers. Of the eight wells drilled in 2006, twowells were completed and six wells were pending completion at December 31.XTO Energy has advised the trustee that it does not plan to perform anyworkovers or drill wells in the Green River Basin during 2007. XTO Energy iscontinuing its efforts to reduce pipeline pressure which has shown potentialfor increasing production and extending field life in the Fontenelle Field.

Potentialdevelopment activities for the underlying properties in this area include:

·       installingartificial lift,

·       restimulatingproducing intervals utilizing new technology,

·       additionalcompression to lower line pressures, and

·       openingnew producing zones in existing 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 2006, the fuel charge was 1.2% of thevolumes produced and the processing fee was $0.10 per MMBtu. The marketing subsidiarythen sells the residue gas to third parties based upon a spot sales price andpays the net sales proceeds to XTO Energy. The marketing subsidiary does notreceive a marketing fee. The gas not sold under the above arrangement is soldeither under a similar arrangement where the fee is $0.16 per MMBtu, or under acontract where XTO Energy directly sells the gas to a third party on the leaseat an adjusted index price. Condensate is sold at the lease to an independentthird party at market rates.

**Producing Acreageand 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. Operated wells areoperated by XTO Energy and nonoperated wells are operated by other operators.

Theunderlying properties are interests in developed properties located primarilyin gas producing regions of Kansas, Oklahoma and Wyoming. The following is asummary of the approximate producing acreage of the underlying properties at December 31,2006. 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 |       |

 

9

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Thefollowing is a summary of the producing wells on the underlying properties asof December 31, 2006:

| ** ** | ** ** | **Operated** | ** ** | **Nonoperated** | ** ** | ** ** | ** ** | ** ** | ** ** |
|------------|------------|--------------|------------|-----------------|------------|------------|------------|------------|------------|
| ** ** | ** ** | **Wells**    | ** ** | **Wells**       | ** ** | **Total**  | ** ** |
| ** ** | ** ** | **Gross**    | ** ** | **Net**         | ** ** | **Gross**  | ** ** | **Net**    | ** ** | **Gross** | ** ** | **Net** | ** ** |
| Gas        |       | 1,212        |       | 1,086.6         |       |       | 276        |       |       | 64.2 |   | 1,488 |   | 1,150.8 |   |
| Oil        |       | 45           |       | 40.1            |       |       | 9          |       |       | 2.2 |   | 54 |   | 42.3 |   |
| Total      |       | 1,257        |       | 1,126.7         |       |       | 285        |       |       | 66.4 |   | 1,542 |   | 1,193.1 |   |

 

Thefollowing is a summary of the number of wells drilled on the underlyingproperties during the years indicated. Unless otherwise indicated, all wellsdrilled are developmental. There were 13 gross (7.6 net) wells inprocess of drilling at December 31, 2006.

| ** **            | ** ** | **2006**  | ** ** | **2005** | ** ** | **2004**  | ** ** |
|-----------------------|------------|-----------|------------|----------|------------|-----------|------------|
| ** **            | ** ** | **Gross** | ** ** | **Net**  | ** ** | **Gross** | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** |
| Completed gas  wells  |       |      | 44         |     |       | 28.8      |       |   | 41 |   |   | 29.2 |   |   | 25 |   |   | 19.2 |   |
| Completed oil  wells  |       |      | 3          |     |       | 0.6       |       |   | 1 |   |   | 1.0 |   |   | — |   |   | — |   |
| Non-productive  wells |       |      | 1          |     |       | 0.1       |       |   | 1 |   |   | 0.5 |   |   | 4 |   |   | 1.5 |   |
| Total *(a)*           |       |      | 48         |     |       | 29.5      |       |   | 43 |   |   | 30.7 |   |   | 29 |   |   | 20.7 |   |

----

*(a)**            *Included in totals are 17 gross (4.3 net) wells in 2006, 10 gross (2.4net) wells in 2005 and 7 gross (1.1 net) wells in 2004, drilled on nonoperatedinterests.

**Oil and Natural GasProduction**

Trustproduction is recognized in the period net profits income is received, which isthe month following receipt by XTO Energy, and generally two months after thetime of production. Oil and gas production and average sales pricesattributable to the underlying properties and the net profits interests for thethree years ended December 31, 2006 were as follows:

| ** **               | ** ** | **2006**        | ** ** | **2005**        | ** ** | **2004**        | ** ** |
|--------------------------|------------|-----------------|------------|-----------------|------------|-----------------|------------|
| **Production**           |       |            |       |            |       |            |       |
| *Underlying Properties*  |       |            |       |            |       |            |       |
| Gas—Sales (Mcf)     |       | 29,628,079      |       | 29,986,698      |       | 30,238,663      |       |
| Average per day (Mcf)    |       | 81,173          |       | 82,155          |       | 82,619          |       |
| Oil—Sales (Bbls)    |       | 332,525         |       | 325,193         |       | 318,694         |       |
| Average per day (Bbls)   |       | 911             |       | 891             |       | 871             |       |
| *Net  Profits Interests* |       |            |       |            |       |            |       |
| Gas—Sales (Mcf)     |       | 12,871,453      |       | 15,836,681      |       | 16,462,378      |       |
| Average per day (Mcf)    |       | 35,264          |       | 43,388          |       | 44,979          |       |
| Oil—Sales (Bbls)    |       | 145,230         |       | 177,980         |       | 184,487         |       |
| Average per day (Bbls)   |       | 398             |       | 488             |       | 504             |       |
| **Average  Sales Price** |       |            |       |            |       |            |       |
| Gas (per Mcf)            |       | $** **6.59 |       | $** **6.64 |       | $** **4.99 |       |
| Oil (per Bbl)            |       | $63.73          |       | $52.27          |       | $38.11          |       |

 

**Oil and Natural GasReserves**

***General***

Miller and Lents, Ltd., independent petroleumengineers, has estimated oil and gas reserves attributable to the underlyingproperties as of December 31, 2006, 2005, 2004 and 2003. The estimated 

10

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reserves for theunderlying properties are then used by XTO Energy to calculate the estimatedoil 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.

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.These costs are the legal obligation of XTO Energy as the owner of theunderlying working interests and will only be deducted from net proceedspayable to the trust if net proceeds from the related conveyance exceed suchcosts when paid, subject to excess cost carryforward provisions as describedunder Item 1.

Year-end weighted averagerealized gas prices used to determine the standardized measure were $5.60 perMcf in 2006, $8.72 per Mcf in 2005, $5.68 per Mcf in 2004 and $5.76 per Mcf in2003. 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 2006,$57.75 per Bbl in 2005, $40.25 per Bbl in 2004 and $29.25 per Bbl in 2003.

***Proved Reserves***

| ** **                             | ** ** | **Underlying  Properties** | ** ** | **Net Profits Interests** | ** ** |
|----------------------------------------|------------|----------------------------|------------|-------------------------------------|------------|
| ***(in thousands)***              | ** ** | **Gas**                    | ** ** | **Oil**                             | ** ** | **   Gas   ** | ** ** | **   Oil   ** | ** ** |
| ** **                             | ** ** | **(Mcf)**                  | ** ** | **(Bbls)**                          | ** ** | **(Mcf)** | ** ** | **(Bbls)** | ** ** |
| 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 |       | 17,853                     |       | 203                                 |       | 8,938 |   |   | 102 |   |   |
| Revisions of prior  estimates          |       | (10,817                    | )          | 187                                 |       | (37,322 | ) |   | (195 | ) |   |
| Production—sales volumes          |       | (29,628                    | )          | (333                                | )          | (12,871 | ) |   | (145 | ) |   |
| Balance, December 31, 2006        |       | 420,452                    |       | 3,838                               |       | 230,676 |   |   | 2,195 |   |   |

 

11

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Extensions, additions anddiscoveries in 2004, 2005 and 2006 are primarily related to delineation ofadditional proved undeveloped reserves in the Anadarko Basin. Revisions ofprior estimates of the proved gas reserves for the underlying properties ineach year are primarily because of changes in the year-end gas and oil prices. Higherupward and downward revisions for the net profits interests as compared withthe underlying properties in each year were caused by changes in year-end oiland gas prices and estimated future production and development costs whichresulted in an increase or decrease in gas reserves allocated to the trust.

***Proved DevelopedReserves***

| ***(in thousands)*** | ** ** | **Underlying  Properties** | ** ** | **Net Profits  Interests** | ** ** |
|---------------------------|------------|----------------------------|------------|---------------------------------|------------|
| ** **                | ** ** | **Gas**                    | ** ** | **Oil**                         | ** ** | **Gas** | ** ** | **Oil** | ** ** |
| ** **                | ** ** | **(Mcf)**                  | ** ** | **(Bbls)**                      | ** ** | **(Mcf)** | ** ** | **(Bbls)** | ** ** |
| 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 |   |
| December 31,  2006   |       | 361,915                    |       | 3,369                           |       | 202,794 |   | 1,964 |   |

 

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

| ***(in thousands)***    | ** ** | **December 31** | ** ** |
|------------------------------|------------|----------------------|------------|
| ** **                   | ** ** | **2006**             | ** ** | **2005** | ** ** | **2004** | ** ** |
| ***Underlying  Properties*** |       |                 |       |   |   |   |   |
| Future cash  inflows         |       | $                    | 2,574,507  |   | $ | 4,092,655 |   | $ | 2,680,376 |   |
| Future costs:                |       |                 |       |   |   |   |   |
| Production                   |       | 858,794              |       | 1,109,882 |   | 856,280 |   |
| Development                  |       | 86,744               |       | 80,610 |   | 57,059 |   |
| Future net cash  flows       |       | 1,628,969            |       | 2,902,163 |   | 1,767,037 |   |
| 10% discount  factor         |       | 830,281              |       | 1,511,732 |   | 895,304 |   |
| Standardized measure         |       | $                    | 798,688    |   | $ | 1,390,431 |   | $ | 871,733 |   |
| ***Net  Profits Interests*** |       |                 |       |   |   |   |   |
| Future cash  inflows         |       | $                    | 1,420,936  |   | $ | 2,515,738 |   | $ | 1,539,521 |   |
| Future production  taxes     |       | 117,760              |       | 194,008 |   | 125,891 |   |
| Future net cash  flows       |       | 1,303,176            |       | 2,321,730 |   | 1,413,630 |   |
| 10% discount  factor         |       | 664,225              |       | 1,209,385 |   | 716,244 |   |
| Standardized  measure        |       | $                    | 638,951    |   | $ | 1,112,345 |   | $ | 697,386 |   |

 

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

| ***(in thousands)***                                       | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
|-----------------------------------------------------------------|------------|------------|------------|------------|------------|------------|------------|
| ** **                                                      | ** ** | **2006**   | ** ** | **2005**   | ** ** | **2004**   | ** ** |
| ***Underlying  Properties***                                    |       |       |       |       |       |       |       |
| Standardized  measure, January 1                           |       | $          | 1,390,431  |       | $          | 871,733    |       | $ | 925,812 |   |
| Revisions:                                                      |       |       |       |       |       |       |       |
| Prices and costs                                                |       | (578,041   | )          | 566,014    |       | (36,596    | )          |
| Quantity estimates                                              |       | 5,912      |       | 5,744      |       | (7,115     | )          |
| Accretion of discount                                           |       | 119,526    |       | 75,570     |       | 79,856     |       |
| Future development costs                                        |       | (53,060    | )          | (56,072    | )          | (22,304    | )          |
| Production rates and other                                      |       | (944       | )          | (92        | )          | (176       | )          |
| Net revisions                                                   |       | (506,607   | )          | 591,164    |       | 13,665     |       |
| Extensions,  additions and discoveries                          |       | 28,915     |       | 58,946     |       | 34,656     |       |
| Production                                                      |       | (165,751   | )          | (170,612   | )          | (123,700   | )          |
| Development costs                                               |       | 51,700     |       | 39,200     |       | 21,300     |       |
| Net change                                                      |       | (591,743   | )          | 518,698    |       | (54,079    | )          |
| Standardized measure, December 31                          |       | $          | 798,688    |       | $          | 1,390,431  |       | $ | 871,733 |   |
| ***Net Profits Interests***                                     |       |       |       |       |       |       |       |
| Standardized  measure, January 1                           |       | $          | 1,112,345  |       | $          | 697,386    |       | $ | 740,650 |   |
| Extensions,  additions and discoveries                          |       | 23,132     |       | 47,157     |       | 27,724     |       |
| Accretion of discount                                           |       | 95,621     |       | 60,456     |       | 63,885     |       |
| Revisions of  prior estimates, changes in price and other *(a)* | * *   | (500,906   | )          | 412,475    |       | (52,953    | )          |
| Net profits  income                                             |       | (91,241    | )          | (105,129   | )          | (81,920    | )          |
| Standardized  measure, December 31                         |       | $          | 638,951    |       | $          | 1,112,345  |       | $ | 697,386 |   |

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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 toprohibit market 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.

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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. Should thetrust be required to withhold state taxes, distributions to the unitholderswould be reduced by the required amount, subject to the unitholder’s right tofile a state tax return to claim any refund 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 SalesInformation**

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. Themonthly published index price is generally the price established during thelast five business days of the month preceding the month of delivery for thespecific delivery location, which is based on the NYMEX price less the locationdifferential during this period. Any marketing gains or losses are not includedin trust net proceeds. Oil production is generally marketed at the wellhead tothird parties at the best available price. XTO Energy arranges for some of itsnatural gas to be processed by unaffiliated third parties and markets thenatural gas liquids. The natural gas attributable to the underlying propertiesis marketed under contracts existing at trust inception. Contracts coveringproduction from the Ringwood area of the Major County area are generally forthe life of the lease, and the contract for the majority of production from theHugoton area was extended through 2007. If new contracts are entered withunaffiliated third parties, the proceeds from sales under those new contractswill be included in gross proceeds from the underlying properties. If newcontracts are entered with XTO Energy’s marketing subsidiary, it may charge XTOEnergy a fee that may not exceed 2% of the sales price of the oil and naturalgas received from unaffiliated parties. The sales price is net of anydeductions for transportation from the wellhead to the unaffiliated parties andany gravity or quality adjustments.

14

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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 behalfof the United 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. In response to a motion to dismiss filed byXTO Energy and other defendants in October 2006, the district judge heldthat Grynberg failed to establish the jurisdictional requirements to maintainthe action against XTO Energy and other defendants and dismissed the actionsfor lack of subject matter jurisdiction. Grynberg has filed an appeal ofthis decision. While XTO Energy is unable to predict the final outcome of thiscase or estimate the amount of any possible loss, it has informed the trusteethat it believes that the allegations of this lawsuit are without merit andintends to vigorously defend the action. However, an order to change measuringpractices or a related settlement could adversely affect the trust by reducingnet proceeds in the future by an amount that is presently not determinable,but, in XTO Energy management’s opinion, is not currently expected to bematerial to the trust’s annual distributable income, financial position orliquidity.

An amended petition for a class action lawsuit, *Beer, et al. v. XTO Energy Inc.*, was filedin January 2006, in the District Court of Texas County, Oklahoma byroyalty owners of natural gas wells in Oklahoma. The plaintiffs allege that XTOEnergy has not properly accounted to the plaintiffs for the royalties to whichthey are entitled and seek an accounting regarding the natural gas and otherproducts produced from their wells and the prices paid for the natural gas andother products produced, and for payment of the monies allegedly owed since June 2002,with a certain limited number of plaintiffs claiming monies owed for additionaltime. A hearing on the class certification has not been scheduled. Theplaintiffs have not stated an amount they are seeking. XTO Energy has informedthe trustee that it believes that it has strong defenses to this lawsuit andintends to vigorously defend its position. However, if XTO Energy ultimatelymakes any settlement payments, the trust will bear its 80% share of suchsettlement related to production from the underlying properties. Additionally,if a judgment or settlement increases the amount of future payments to royaltyowners, the trust would bear its proportionate share of the increased paymentsthrough reduced net proceeds. XTO Energy has informed the trustee that,although the amount of any reduction in net proceeds is not presentlydeterminable, in its management’s opinion, the amount is not currently expectedto be material to the trust’s annual distributable income, financial positionor 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 2006.

15

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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 31,2006 is incorporated herein by reference.

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

**Item6.**                        *Selected Financial Data*

| ** **                     | ** ** | **Year Ended December 31** | ** ** |
|--------------------------------|------------|-------------------------------------------|------------|
| ** **                     | ** ** | **2006**                                  | ** ** | **2005** | ** ** | **2004** | ** ** | **2003** | ** ** | **2002** | ** ** |
| Net Profits  Income            |       | $                                         | 91,241,196 |   | $ | 105,129,321 |   | $ | 81,920,014 |   | $ | 80,687,778 |   | $ | 29,934,195 |   |
| Distributable  Income          |       | 90,910,760                                |       | 104,831,880 |   | 81,596,920 |   | 80,373,120 |   | 29,572,360 |   |
| Distributable  Income per Unit |       | 2.272769                                  |       | 2.620797 |   | 2.039923 |   | 2.009328 |   | 0.739309 |   |
| Distributions per  Unit        |       | 2.272769                                  |       | 2.620797 |   | 2.039923 |   | 2.009328 |   | 0.739309 |   |
| Total Assets at Year-End       |       | 165,609,772                               |       | 185,459,610 |   | 189,499,334 |   | 198,952,087 |   | 208,721,083 |   |
|                                |            |                                           |            |  |  |  |  |  |  |  |  |  |  |  |  |  |

 

**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 thethree-year period ended December 31, 2006 in the trust’s annual report tounitholders for the year ended December 31, 2006 is incorporated herein byreference.

**Liquidity andCapital 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 thenet profits interests. 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 SheetArrangements**

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.

**ContractualObligations**

Asshown below, the trust had no obligations and commitments to make futurecontractual payments as of December 31, 2006, other than the December distributionpayable to unitholders in January 2007, as reflected in the statement ofassets, liabilities and trust corpus.

| ** **                           | ** ** | **Payments due by Period** | ** ** |
|--------------------------------------|------------|-------------------------------------------|------------|
| ** **                           | ** ** | ** **                                | ** ** | **Less than** | ** ** | ** ** | ** ** | ** ** | ** ** | **More than** | ** ** |
| ** **                           | ** ** | **Total**                                 | ** ** | **1 Year** | ** ** | **1-3 Years** | ** ** | **3-5 Years** | ** ** | **5 Years** | ** ** |
| Distribution  payable to unitholders |       | $                                         | 1,813,000  |   | $ | 1,813,000 |   |   | $ | — |   |   |   | $ | — |   |   |   | $ | — |   |   |
|                                      |            |                                           |            |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |

 

16

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**Related PartyTransactions**

The underlying properties from which the net profitsinterests were carved are currently owned by XTO Energy, which operatesapproximately 94% of the underlying properties. In computing net proceeds, XTOEnergy deducts a monthly overhead charge for reimbursement of administrativeexpenses on the underlying properties it operates. As of December 31,2006, the monthly overhead charge, based on the number of operated wells, wasapproximately $716,000 ($572,800 net to the trust) and is subject to annualadjustment based on an oil and gas industry index.

In May 2006, XTO Energy distributed all of itsremaining 21.7 million trust units as a dividend to its common stockholders. XTOEnergy currently is not a unitholder of the trust. In January 2006, XTOEnergy announced that it would consider selling the underlying properties. However,XTO Energy advised the trustee in August 2006, that after a full review,it has decided to retain ownership of these underlying property interests atthis time.

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, 2006. Total gas sales from theunderlying properties to XTO Energy’s wholly owned subsidiaries were $103.2million for 2006, or 53% of total gas sales, $107.9 million for 2005, or 54% oftotal gas sales and $81.7 million for 2004, or 54% of total gas sales.

**Critical AccountingPolicies**

The financial statementsof the trust are significantly affected by its basis of accounting and estimatesrelated to its oil and gas properties and proved reserves, as summarized 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, 2006.

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. Accordingly, there areno fair value estimates included in the financial statements based on eitherexchange or nonexchange trade values.

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*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 FinancialAccounting Standards Board and the Securities and Exchange Commission. Suchassumptions include using year-end oil and gas prices and year-end costs forestimated future development and production expenditures. Discounted future netcash flows 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-LookingStatements**

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, future development plans, increased density drilling, maintenanceprojects, development, production and other costs, oil and gas prices, pricingdifferentials, proved reserves, production levels, litigation, regulatorymatters and competition. Such forward-looking statements are based on XTOEnergy’s current plans, expectations, assumptions, projections and estimatesand are identified by words such as “expects,” “intends,” “plans,” “projects,” “anticipates,”“predicts,” “believes,” “goals,” “estimates,” “should,” “could”, and similarwords that convey the uncertainty of future events. These statements are notguarantees of future performance and involve certain risks, uncertainties andassumptions that are difficult to predict. Therefore, actual results may differmaterially from expectations, estimates or assumptions expressed in, impliedin, or forecasted in such forward-looking statements. Some of the risk factorsthat could 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 specific short-termcash investments. Therefore, the trust cannot hold any derivative financialinstruments. As a result of the limited nature of the trust’s borrowing andinvesting activities, the trust is not subject to any material interest ratemarket risk. Additionally, any gains or losses from any hedging activities 

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conductedby XTO Energy are specifically excluded from the calculation of net proceedsdue the trust under the forms of the conveyances. The trust does not engage intransactions in foreign currencies which could expose the trust to any foreigncurrency 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 February 28, 2007, appearing in the trust’s annual report tounitholders for the year ended December 31, 2006, 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 31,2006.

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

*Conclusion Regarding the Effectiveness of DisclosureControls 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 on Internal Control Over FinancialReporting*

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, 2006. Thetrustee’s assessment of the effectiveness of the trust’s internal control overfinancial reporting as of December 31, 2006 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 31,2006 which is incorporated herein by reference.

There were no changes inthe trust’s internal control over financial reporting during the quarter ended December 31,2006 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, 2006, with the exception of one latefiling related to one transaction by an immediate family member of Mr. JackP. Randall, a director of XTO Energy. This transaction has now been reported.

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*

The trustee received the following annual compensationfrom 2004 through 2006 as specified in the trust indenture:

| ** **                                     | ** ** | ** **                                                           | ** ** | **Other Annual**                                                                 | ** ** |
|------------------------------------------------|------------|----------------------------------------------------------------------|------------|---------------------------------------------------------------------------------------|------------|
| **Name and Principal Position** | ** ** | **     Year     ** | ** ** | **     Compensation (1)     ** | ** ** |
| Bank of America, N.A.,  Trustee                |       |                                                                 | 2006       |                                                                                  |       |   | $ | 47,410 |   |   |
|                                           |       |                                                                 | 2005       |                                                                                  |       |   | 35,000 |   |   |
|                                           |       |                                                                 | 2004       |                                                                                  |       |   | 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)   *Security Ownership of Certain Beneficial Owners.*Thetrustee is not aware of any person who beneficially owns more than 5% of theoutstanding units.

(b)   *Security Ownership of Management.*Thetrust has no directors or executive officers. As of February 22, 2007,Bank of America, N.A. owned, in various fiduciary capacities, 99,610 units,with a shared right to vote 17,156 of these units and no right to vote 82,454of these units. Bank of America, N.A. disclaims any beneficial interests inthese units. The number of units reflected in this paragraph includes unitsheld 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.

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**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, 2006 was approximately $716,000 per month, or$8,592,000 annually (net to the trust of $572,800 per month or $6,873,600annually), 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 2004 through 2006 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, 2006and 2005:

| ** **          | ** ** | **2006** | ** ** | **2005** | ** ** |
|---------------------|------------|----------|------------|----------|------------|
| Audit fees          |       | $        | 71,750     |     | $          | 66,000 |   |
| Audit-related  fees |       | —   |       | —   |       |
| Tax fees            |       | —   |       | —   |       |
| All other fees      |       | —   |       | —   |       |
|                |       | $        | 71,750     |     | $          | 66,000 |   |

 

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

**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)*

IndependentRegistered Public Accounting Firm Reports

Statementsof Assets, Liabilities and Trust Corpus at December 31, 2006 and 2005

Statementsof Distributable Income for the years ended December 31, 2006, 2005 and2004

Statementsof Changes in Trust Corpus for the years ended December 31, 2006, 2005 and2004

Notes to FinancialStatements

2.     *Financial Statement Schedules*

Financialstatement schedules are omitted because of the absence of conditions underwhich they are required or because the required information is given in thefinancial statements or notes thereto.

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. |   |
|-----|--------|-----|--------|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|--------|

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|        |   | (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, 2006 |   |
| (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 1, 2007 | 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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