**Exhibit 13**

**HUGOTONROYALTY TRUST**

 

GLOSSARY OF TERMS

The following are definitions of significant terms used in this AnnualReport:
| *Bbl*                   |     | Barrel (of oil)                                                                                                                                                                                                                                            |
|-------------------------|----------|------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| * *                |     |                                                                                                                                                                                                                                                       |
| *Bcf*                   |     | Billion cubic feet (of natural gas)                                                                                                                                                                                                                        |
| * *                |     |                                                                                                                                                                                                                                                       |
| *Mcf*                   |     | Thousand cubic feet (of natural gas)                                                                                                                                                                                                                       |
| * *                |     |                                                                                                                                                                                                                                                       |
| *MMBtu*                 |     | One million British Thermal Units, a common energy  measurement                                                                                                                                                                                            |
| * *                |     |                                                                                                                                                                                                                                                       |
| *net proceeds*          |     | Gross proceeds received by XTO Energy from sale of  production from the underlying properties, less applicable costs, as defined  in the net profits interest conveyances                                                                                  |
| * *                |     |                                                                                                                                                                                                                                                       |
| *net profits income*    |     | Net proceeds multiplied by the net profits  percentage of 80%, which is paid to the trust by XTO Energy. “Net profits  income” is referred to as “royalty income” for tax reporting purposes.                                          |
| * *                |     |                                                                                                                                                                                                                                                       |
| *net profits interest*  |     | An interest in an oil and gas property measured by  net profits from the sale of production, rather than a specific portion of  production. The following defined net profits interests were conveyed to the  trust from the underlying properties:        |
| * *                |     |                                                                                                                                                                                                                                                       |
|                    |     | *80% net profits interests* - interests that entitle the trust  to receive 80% of the net proceeds from the underlying properties.                                                                                                                         |
| * *                | * * | * *                                                                                                                                                                                                                                                   |
| *underlying properties* |     | XTO Energy’s interest in certain oil and gas  properties from which the net profits interests were conveyed. The underlying  properties include working interests in predominantly gas-producing  properties located in Kansas, Oklahoma and Wyoming. |
| * *                |     |                                                                                                                                                                                                                                                       |
| *working interest*      |     | An operating interest in an oil and gas property  that provides the owner a specified share of production that is subject to  all production expense and development costs                                                                                 |

 

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**THE TRUST**

 

Hugoton Royalty Trust was created on December 1, 1998 when XTO EnergyInc. conveyed 80% net profits interests in certain predominantly gas-producingproperties located in Kansas, Oklahoma and Wyoming to the trust.  The net profits interests are the only assetsof the trust, other than cash held for trust expenses and for distribution tounitholders.

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

**UNITS OF BENEFICIAL INTEREST**

 

The units of beneficial interest in the trustbegan trading on the New York Stock Exchange on April 9, 1999 under the symbol “HGT.”  The following are the high and low unit salesprices and total cash distributions per unit paid by the trust during eachquarter of 2006 and 2005:

| ** **  | ** ** | **Sales Price** | ** ** | **Distributions** | ** ** |
|-------------|------------|----------------------|------------|-------------------|------------|
| **Quarter** | ** ** | ** **           | ** ** | **High**          | ** ** | **Low** | ** ** | **per Unit** | ** ** |
|        |       |                 |       |              |       |   |   |
| **2006**    |       |                 |       |              |       |   |   |
| **First**   | ** ** | **$**                | **39.00**  | ** **        | **$**      | **29.27** | ** ** | **$** | **0.976040** | ** ** |
| **Second**  | ** ** | **32.20**            | ** ** | **25.05**         | ** ** | **0.524306** | ** ** |
| **Third**   | ** ** | **31.85**            | ** ** | **24.30**         | ** ** | **0.423020** | ** ** |
| **Fourth**  | ** ** | **28.20**            | ** ** | **24.15**         | ** ** | **0.349403** | ** ** |
| ** **  | ** ** | ** **           | ** ** | ** **        | ** ** | **$** | **2.272769** | ** ** |
|        |       |                 |       |              |       |   |   |
| 2005        |       |                 |       |              |       |   |   |
| First       |       | $                    | 32.19      |              | $          | 23.72 |   | $ | 0.642454 |   |
| Second      |       | 31.05                |       | 24.88             |       | 0.570801 |   |
| Third       |       | 41.84                |       | 29.80             |       | 0.607605 |   |
| Fourth      |       | 41.80                |       | 31.03             |       | 0.799937 |   |
|        |       |                 |       |              |       | $ | 2.620797 |   |
|             |            |                      |            |                   |            |  |  |  |  |  |  |  |

 

At December 31, 2006, there were 40,000,000 units outstanding andapproximately 1,254 unitholders of record; 39,101,894 of these units were heldby depository institutions.  In May 2006,XTO Energy distributed all of its remaining 21.7 million trust units as adividend to its common stockholders.  XTOEnergy currently is not a unitholder of the trust.

In January 2006, XTO Energy announced that it would consider sellingthe underlying properties.  However, XTOEnergy advised the trustee in August 2006, that after a full review, it hasdecided to retain ownership of these underlying property interests at thistime.

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***Forward-Looking Statements***

*ThisAnnual Report, including the accompanying Form 10-K, includes “forward-lookingstatements” within the meaning of Section 27A of the Securities Act of1933, as amended, and Section 21E of the Securities Exchange Act of 1934, asamended.  All statements other thanstatements of historical fact included in this Annual Report and Form 10-K,including, without limitation, statements regarding estimates of provedreserves, future development plans and costs, and industry and market conditions,are forward-looking statements that are subject to a number of risks anduncertainties which are detailed in Part I, Item 1A of theaccompanying Form 10-K.  AlthoughXTO Energy and the trustee believe that the expectations reflected in suchforward-looking statements are reasonable, neither XTO Energy nor the trusteecan give any assurance that such expectations will prove to be correct.*

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**SUMMARY**

 

The trust was created to collect and distribute to unitholders monthlynet profits income related to the 80% net profits interests.  Such net profits income is calculated as 80%of the net proceeds received from certain working interests in predominantlygas-producing properties in Kansas, Oklahoma and Wyoming.  Net proceeds from properties in each stateare calculated by deducting production expense, development costs and overheadfrom revenues.  If monthly costs exceedrevenues from the underlying properties in any state, such excess costs must berecovered, with accrued interest, from future net proceeds of that state andcannot reduce net profits income from another state.  Excess costs generally can occur duringperiods of higher development activity and lower gas prices.

—                             Cost Depletion is generally available tounitholders as a deduction from royalty income. Available depletion is dependent upon the unitholder’s cost ofunits, purchase date and prior allowable depletion.  It may be more beneficial for unitholders todeduct percentage depletion.  Unitholdersshould consult their tax advisors for further information.

*As an example, a unitholder that acquired units inJanuary 2006 and held them throughout 2006 would be entitled to a costdepletion deduction of approximately 5% of his cost.  Assuming a cost of $38.00 per unit, costdepletion would offset approximately 79% of 2006 taxable trust income.  Assuming a 30% tax rate, the 2006 taxableequivalent return as a percentage of unit cost would be 8%.  (NOTE- Because the units are a depletingasset, a portion of this return is effectively a return of capital.)*

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**TO UNITHOLDERS**

 

We are pleased to present the 2006 Annual Report of the Hugoton RoyaltyTrust.  This report includes a copy ofthe trust’s 2006 Form 10-K as filed with the Securities and ExchangeCommission.  Both reports containimportant information about the trust’s net profits interests, includinginformation provided to the trustee by XTO Energy, and should be read inconjunction with each other.

For the year ended December 31, 2006, net profits income totaled$91,241,196.  After adding interest incomeof $198,542 and deducting trust administration expense of $528,978,distributable income was $90,910,760 or $2.272769 per unit.  Net profits income and distributions were 13%lower than 2005 amounts primarily because of higher development costs and productionexpense on the underlying properties.

Natural gas prices averaged $6.59 per Mcf for 2006, 1% lower than the2005 average price of $6.64 per Mcf.  Theaverage 2006 oil price was $63.73 per Bbl, 22% higher than the 2005 averageprice of $52.27 per Bbl.

Gas sales volumes from the underlying properties for 2006 were29,628,079 Mcf, or 81,173 Mcf per day, or a 1% decline from 82,155 Mcf per dayin 2005.  Oil sales volumes from theunderlying properties were 332,525 Bbls, or 911 Bbls per day in 2006, or anincrease of 2% from 891 Bbls per day in 2005. For further information on sales volumes and product prices, see “Trustee’sDiscussion and Analysis.”

As of December 31, 2006, proved reserves for the underlying propertieswere estimated by independent engineers to be 420.5 Bcf of natural gas and 3.8million Bbls of oil.  Natural gasreserves for the underlying properties declined 22.6 Bcf primarily due tocurrent year production and revisions related to lower year-end gas prices,partially offset by additions from development activity.  Oil reserves for the underlying propertieswere relatively unchanged from year-end 2005 primarily because production wasoffset by reserve additions from development activity.  Based on an allocation of these reserves,proved reserves attributable to the net profits interests were estimated to be230.7 Bcf of natural gas and 2.2 million Bbls of oil.  Estimated gas and oil reserves attributableto the net profits interests declined from previously reported reserves atyear-end 2005, as current year production and revisions due to lower year-endprices were only partially offset by additions from developmentactivities.  All reserve informationprepared by independent engineers has been provided to the trustee by XTOEnergy.

Estimated future net cash flows from proved reserves of the net profitsinterests at December 31, 2006 are $1.3 billion.  Using an annual discount factor of 10%, thepresent value of estimated future net cash flows at December 31, 2006 is$639 million.  Proved reserve estimatesand related future net cash flows have been determined based on a year-endaverage realized gas price of $5.60 per Mcf and a year-end West TexasIntermediate posted oil price of $57.75 per Bbl.  Other guidelines used in estimating provedreserves, as prescribed by the Financial Accounting Standards Board, aredescribed under Item 2 of the accompanying Form 10-K.  The present value of estimated future netcash flows is not representative of the market value of trust units.

As disclosed in the tax instructions provided to unitholders inFebruary 2007, trust distributions are considered portfolio income, rather thanpassive income.  Unitholders shouldconsult their tax advisors for further information.

Hugoton Royalty TrustBy:  Bank of America, N.A., Trustee

By:            Nancy G. Willis Vice President

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**THE UNDERLYINGPROPERTIES**

The underlying properties are predominantly gas-producing propertieswith established production histories in the Hugoton area of Oklahoma andKansas, the Anadarko Basin of Oklahoma and the Green River Basin ofWyoming.  The averagereserve-to-production index for the underlying properties as of December 31,2006 is approximately 15 years.  Thisindex is calculated using total proved reserves and estimated 2007 productionfor the underlying properties.  Theprojected 2007 production is from proved developed producing reserves as ofDecember 31, 2006.  Based on estimatedfuture net cash flows at year-end oil and gas prices, the proved reserves ofthe underlying properties are approximately 91% natural gas and 9% oil.  XTO Energy operates approximately 94% of theunderlying properties.

Because the underlying properties are working interests, productionexpense, development costs and overhead are deducted in calculating net profitsincome.  As a result, net profits incomeis affected by the level of maintenance and development activity on theunderlying properties.  See “Trustee’sDiscussion and Analysis - Years Ended December 31, 2006, 2005 and 2004 - Costs.”  Total 2006 development costs deducted for theunderlying properties were $51.7 million, an increase of 32% from the prioryear.  XTO Energy has informed thetrustee that total 2007 budgeted development costs for the underlyingproperties are approximately $46 million.

**Hugoton Area**

Discovered in 1922, the Hugoton area is one of the largest natural gasproducing areas in the United States. During 2006, gas sales volumes from the underlying properties in theHugoton area were 8.6 Bcf, or approximately 29% of total sales volumes from theunderlying properties.  Most of theproduction is from the Chase formation at depths of 2,700 to 2,900 feet.  XTO Energy has informed the trustee that itplans to develop other formations, including the Council Grove, Chester, Morrowand St. Louis formations that underlie the 79,500 net acres held by productionby the Chase formation wells.  XTO Energyhas participated in 3-D seismic shoots covering 30,000 acres of its net acreageposition beneath the Chase formation.

Within this area, XTO Energy successfully drilled three gross (3.0 net)wells and performed 29 workovers in 2006, of which 20 were Chaserestimulations.  XTO Energy has informedthe trustee that it plans to drill up to five wells and perform up to 30workovers during 2007.

**Anadarko Basin**

The Anadarko Basin of western Oklahoma was discovered in 1945.  Gas sales volumes from the underlyingproperties in the Anadarko Basin totaled 12.7 Bcf in 2006, or approximately 43%of total sales volumes from the underlying properties.  XTO Energy is one of the largest producers inthe Ringwood, Northwest Okeene and Cheyenne Valley fields of Major County, theNortheast Cedardale field of Woodward County and the Elk City field of BeckhamCounty, the principal producing regions of the underlying properties in theAnadarko Basin.

In Major County, XTO Energy successfully drilled 12 gross (8.0 net)wells and performed 12 workovers in 2006. XTO Energy has informed the trustee that it plans to drill up to 12wells and perform up to 15 workovers in Major County during 2007.  In Woodward County, XTO Energy successfullydrilled 12 gross (10.4 net) wells and performed five workovers in 2006.  XTO Energy has informed the trustee that itplans to drill up to 11 wells and perform up to eight workovers in WoodwardCounty during 2007.

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In the Elk City field, XTO Energy successfully drilled two gross (1.8net) wells and performed three workovers in 2006.  XTO Energy has informed the trustee that itplans to drill up to four wells and perform up to six workovers within the ElkCity field during 2007.

**Green River Basin**

The Green River Basin is located in southwestern Wyoming.  Natural gas was discovered in the FontenelleField of the Green River Basin in the early 1970s.  The producing reservoirs are the Cretaceous-agedFrontier, Baxter and Dakota sandstones at depths ranging from 7,500 to 10,000feet.  Gas sales volumes from theunderlying properties in the Green River Basin were 8.3 Bcf in 2006, orapproximately 28% of total sales volumes from the underlying properties.

In 2006, XTO Energy successfully drilled eight gross (8.0 net) wellsand performed ten workovers.  Of theeight wells drilled in 2006, two wells were completed and six wells werepending completion at December 31. XTO Energy has informed the trustee that it does not plan to perform anyworkovers or drill wells in the Green River Basin during 2007.  XTO Energy is continuing its efforts toreduce pipeline pressure which has shown potential for increasing production andextending field life in the Fontenelle Field.

**Estimated Proved Reserves and Future Net Cash Flows**

The following are proved reserves of the underlying properties, asestimated by independent engineers, and proved reserves and future net cashflows from proved reserves of the net profits interests, based on an allocationof these reserves, at December 31, 2006:
| ** **                | ** ** | **Underlying Properties**    | ** ** | **Net Profits Interests**        | ** ** |
|---------------------------|------------|-----------------------------------|------------|--------------------------------------------|------------|
| ** **                | ** ** | **Proved Reserves (a)** | ** ** | **Proved Reserves (a) (b)** | ** ** | **Future Net Cash Flows** | ** ** |
| ** **                | ** ** | **Gas**                           | ** ** | **Oil**                                    | ** ** | **Gas** | ** ** | **Oil** | ** ** | **from Proved Reserves (a) (c)** | ** ** |
| ** **                | ** ** | **(Mcf)**                         | ** ** | **(Bbls)**                                 | ** ** | **(Mcf)** | ** ** | **(Bbls)** | ** ** | **Undiscounted** | ** ** | **Discounted** | ** ** |
| ***(in thousands)*** | ** ** | ** **                        | ** ** | ** **                                 | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
|                      |       |                              |       |                                       |       |   |   |   |   |   |   |   |   |
| Oklahoma                  |       | 264,571                           |       | 3,603                                      |       | 151,772 |   | 2,075 |   | $ | 926,886 |   | $ | 455,237 |   |
| Wyoming                   |       | 124,772                           |       | 149                                        |       | 63,732 |   | 76 |   | 313,194 |   | 149,243 |   |
| Kansas                    |       | 31,109                            |       | 86                                         |       | 15,172 |   | 44 |   | 63,096 |   | 34,471 |   |
|                      |       |                              |       |                                       |       |   |   |   |   |   |   |   |   |
| TOTAL                     |       | 420,452                           |       | 3,838                                      |       | 230,676 |   | 2,195 |   | $ | 1,303,176 |   | $ | 638,951 |   |

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

(b)               Since the trust has defined net profitsinterests, the trust does not own a specific percentage of the oil and gasreserves.  Because trust reservequantities are determined using an allocation formula, any fluctuations inactual or assumed prices or costs will result in revisions to the estimatedreserve quantities allocated to the net profits interests.

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

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**TRUSTEE’SDISCUSSION AND ANALYSIS**

**Years Ended December 31, 2006, 2005 and 2004**

Net profits income for 2006 was $91,241,196, as compared with$105,129,321 for 2005 and $81,920,014 for 2004. The 13% decrease in net profits income from 2005 to 2006 is primarilythe result of higher development costs and production expense.  The 28% increase in net profits income from2004 to 2005 was primarily the result of higher product prices, partiallyoffset by increased development costs. Over 90% of net profits income in each year was attributable to naturalgas sales.

Trust administration expense was $528,978 in 2006 as compared to$410,083 in 2005 and $357,891 in 2004. Increased administration expense from 2005 to 2006 is primarily becauseof higher unitholder reporting costs related to an increased number ofunitholders.  Increased administrationexpense from 2004 to 2005 was primarily because of increased fees related tothe audit of the trust’s internal control over financial reporting.  Interest income was $198,542 in 2006,$112,642 in 2005 and $34,797 in 2004. Changes in interest income are attributable to fluctuations in netprofits income and interest rates. Distributable income was $90,910,760 or $2.272769 per unit in 2006,$104,831,880 or $2.620797 per unit in 2005 and $81,596,920 or $2.039923 per unitin 2004.

Net profits income is recorded when received by the trust, which is themonth following receipt by XTO Energy, and generally two months after oil andgas production.  Net profits income isgenerally affected by three major factors:

·                  oiland gas sales volumes,

·                  oiland gas sales prices, and

·                  costs deducted in the calculation of netprofits income.

***Volumes***

Underlying gas sales volumes decreased 1% and underlying oil salesvolumes increased 2% from 2005 to 2006 and from 2004 to 2005.  Lower gas sales volumes over these periodswere primarily because of natural production decline and the timing of cashreceipts, which was largely offset by increased production from new wells andworkovers.  Oil sales volumes increasedover these periods primarily because of increased production from new wells andworkovers and the timing of cash receipts, partially offset by naturalproduction decline.

***Prices***

*Gas.*  The 2006 average gas price was$6.59 per Mcf, a 1% decrease from the 2005 average gas price of $6.64 per Mcf,which was 33% higher than the 2004 average gas price of $4.99 per Mcf.  Since early 2004, gas prices have generallybeen increasing due primarily to increased demand and declining North Americanproduction. These trends accelerated in the second half of 2005 due to theeffects of hurricanes on Gulf of Mexico production.  During most of 2006, gas prices trended lowerprimarily because of an adequate natural gas supply inventory due to the warmerthan normal weather during the winter of 2005-2006 and the absence of hurricaneactivity in the Gulf of Mexico in 2006. Much colder temperatures during February 2007 have caused prices topartially rebound.   Prices will continueto be affected by weather, the U.S. economy, the level of North Americanproduction, crude oil prices and import levels of liquified natural gas.  Natural gas prices are expected to remainvolatile.

The trust’s average gas price was $0.93, or 16%, lower than the averageNYMEX price of $5.92 in 2004; $1.46, or 18%, lower than the average NYMEX priceof $8.10 in 2005; and $1.43, or 18%, lower than the

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average NYMEX price of $8.02 in 2006. Because of the effects of the Gulf hurricanes, production from theunderlying properties sold at a wider decrement to NYMEX prices in late 2005and early 2006. The average NYMEX price for November 2006 through January 2007was $7.10 per MMBtu.  AtFebruary 15, 2007, the average NYMEX gas price for the following 12 monthswas $8.09 per MMBtu.  Recent trust gasprices have averaged approximately 15% lower than the NYMEX price.

*Oil.*    The average oil price for2006 was $63.73 per Bbl, 22% higher than the average oil price for 2005 of$52.27 per Bbl, which was 37% higher than the 2004 average oil price of $38.11per Bbl.  Since early 2004, oil priceshave generally been rising primarily because of increasing global demand andsupply shortage concerns, inadequate sour crude refining capacity, reducedproduction as a result of tropical storms and hurricanes in the Gulf of Mexicoin 2005 and political instability. Rising tension in the Middle East caused oil prices to increase torecord levels in July 2006, exceeding $78.00 per Bbl.  Rising crude oil supplies, reducedgeopolitical tension and the potential for lower demand in a slowing U.S.economy have caused recent oil prices to fluctuate between approximately $50.00and $60.00 per Bbl.  Oil prices areexpected to remain volatile.  The averageNYMEX price for November 2006 through January 2007 was $58.68 per Bbl. AtFebruary 15, 2007, the average NYMEX oil price for the following 12 monthswas $60.56 per Bbl.  Recent trust oilprices have averaged approximately 5% lower than the NYMEX price.

See “Gulf of Mexico Hurricanes” below.

***Costs***

The calculation of net profits income includes deductions forproduction expense, development costs and overhead since the related underlyingproperties are working interests.  Ifmonthly costs exceed revenues for any state, these excess costs must berecovered, with accrued interest, from future net proceeds of that state andcannot reduce net profits income from another state.  There have been no excess costs or relatedrecoveries since September 1999.

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

*Production.*  Production expense increased20% from 2005 to 2006 primarily because of increased repair and maintenance andinsurance costs as a result of increased activity and higher industry costs andincreased 3% from 2004 to 2005 primarily because of increased fuel costs.

*Development.*  Development costs deducted were$51.7 million in 2006, $39.2 million in 2005 and $21.3 million in 2004.  Increased development costs are primarily dueto higher costs which are attributable to limited availability of drillingrigs, supplies and labor during a period of rising demand for these resources.

In 2006, underlying budgeted development costs deducted fromdistributions totaled $51.7 million, compared with actual development costs of$55.2 million.  At December 31, 2006,cumulative actual costs exceeded cumulative budgeted costs deducted byapproximately $3.4 million.  Because ofincreased development activity and continued increasing costs, the monthlydevelopment cost deduction was increased twice in 2006.  The deductions were increased to $4.2 millionbeginning with the April 2006 distribution and to $5.0 million beginning withthe August 2006 distribution.  With areduction in development activity in first quarter 2007 and based on thedevelopment budget for 2007, the development cost deduction was lowered to$3.75 million beginning with the February 2007 distribution.  XTO Energy has advised the trustee that thismonthly deduction will continue to be evaluated and revised as necessary.

*Overhead.*  Overhead is charged by XTOEnergy for administrative expenses incurred to support operations of theunderlying properties.  Overheadfluctuates based on changes in the active well count and drilling activity onthe underlying properties, as well as an annual inflation adjustment.

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***Gulf of Mexico Hurricanes***

In late August and September 2005, hurricanes in the Gulf of Mexicodisrupted a significant portion of U.S. oil and gas production, leading tohigher and more volatile commodity prices. These increased prices began affecting distributions to unitholdersbeginning with the November 2005 distribution that was paid in December2005.  The underlying properties to thetrust are not located near the Gulf and related production was not significantlyaffected.  However, because of greatersupply and weaker demand in areas where trust related oil and gas is produced,the price received for such production was significantly lower than NYMEXprices, which are generally representative of the price received for gasdelivered in the Louisiana Gulf coast region. This effect on prices had substantially diminished by the April 2006distribution that was paid in May 2006. Production expense and development costs also increased throughout theindustry because of storm damages and related supply shortages.

**Fourth Quarter 2006 and 2005**

During fourth quarter 2006 the trust received net profits incometotaling $14,067,286 compared with fourth quarter 2005 net profits income of$32,018,800.  The 56% decrease in netprofits income from fourth quarter 2005 to 2006 was primarily because of lowergas prices.

Administration expense was $127,815 and interest income was $36,649,resulting in fourth quarter 2006 distributable income of $13,976,120, or$0.349403 per unit.  Distributable incomefor fourth quarter 2005 was $31,997,480 or $0.799937 per unit.  Distributions to unitholders for the quarterended December 31, 2006 were:

| Record Date  | ** ** | **Payment Date**       | ** ** | **Per Unit** | ** ** |
|-------------------|------------|-----------------------------|------------|-------------------|------------|
| October 31, 2006  |       | November 14, 2006 |       | $                 | 0.167660   |   |
| November 30, 2006 |       | December 14, 2006 |       | 0.136418          |       |
| December 29, 2006 |       | January 16, 2007  |       | 0.045325          |       |
|              |       |                        |       | $                 | 0.349403   |   |

 

The December 2006 distribution, paid in January 2007, was affected bysignificantly lower gas prices for October 2006 gas sales from the underlyingproperties.

***Volumes***

Fourth quarter underlying gas sales volumes decreased 1% and underlyingoil sales volumes increased 12% from 2005 to 2006.  Gas sales volumes decreased primarily becauseof natural production decline, which was largely offset by increased productionfrom new wells and workovers. Increased oil sales volumes are primarily becauseof increased production from new wells and workovers and the timing of cashreceipts, partially offset by natural production decline.

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***Prices***

The average fourth quarter 2006 gas price was $5.28 per Mcf, or 36%lower than the fourth quarter 2005 average price of $8.24 per Mcf.  The average fourth quarter 2006 oil price was$62.05 per Bbl, or 2% higher than the fourth quarter 2005 average price of$60.80 per Bbl.  For further informationabout product prices, see “Years Ended December 31, 2006, 2005 and 2004—Prices”above.

***Costs***

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

*Production.*  Fourth quarter production expenseincreased 19% from 2005 to 2006 primarily because of increased repair andmaintenance and insurance costs, partially offset by decreased fuel costs.

*Overhead.*   Overhead increased 7% fromfourth quarter 2005 to 2006 primarily because of the annual rate adjustmentbased on an oil and gas industry index.

For further information about costs, see “Years Ended December 31,2006, 2005 and 2004—Costs” above.

See Item 7 of the accompanying Form 10-K for disclosures regardingliquidity and capital resources, off-balance sheet arrangements, contractualobligations and commitments, related party transactions and critical accountingpolicies of the trust.  See Item 7A ofthe accompanying Form 10-K for quantitative and qualitative disclosures aboutmarket risk affecting the trust.

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**Calculation of Net Profits Income**

The following is a summary of the calculation of net profits incomereceived by the trust:
| ** **                       | ** ** | ** **                                           | ** **      | ** **                                 | ** ** | ** **        | ** ** | **Three Months** | ** **  |
|----------------------------------|------------|------------------------------------------------------|-----------------|--------------------------------------------|------------|-------------------|------------|-----------------------|-------------|
| ** **                       | ** ** | **Year Ended December 31 *(a)*** | ** **      | **Ended December 31 *(a)*** | ** ** |
| ** **                       | ** ** | **2006**                                             | ** **      | **2005**                                   | ** ** | **2004**          | ** ** | **2006**              | ** **  | **2005** | ** ** |
| **Sales Volumes**                |       |                                                 |            |                                       |       |              |       |                  |        |   |   |
| Gas (Mcf) *(b)*                  |       |                                                 |            |                                       |       |              |       |                  |        |   |   |
| Underlying  properties           | ** ** | **29,628,079**                                       |            | 29,986,698                                 |       | 30,238,663        | ** ** | **7,565,251**         |        | 7,644,787 |   |
| Average per day                  | ** ** | **81,173**                                           |            | 82,155                                     |       | 82,619            | ** ** | **82,231**            |        | 83,096 |   |
| Net profits  interests           | ** ** | **12,871,453**                                       |            | 15,836,681                                 |       | 16,462,378        | ** ** | **2,386,820**         |        | 3,802,922 |   |
|                             | ** ** | ** **                                           |            |                                       |       |              | ** ** | ** **            |        |   |   |
| Oil (Bbls) *(b)*                 |       |                                                 |            |                                       |       |              |       |                  |        |   |   |
| Underlying  properties           | ** ** | **332,525**                                          |            | 325,193                                    |       | 318,694           | ** ** | **89,214**            |        | 79,788 |   |
| Average per day                  | ** ** | **911**                                              |            | 891                                        |       | 871               | ** ** | **970**               |        | 867 |   |
| Net profits  interests           | ** ** | **145,230**                                          |            | 177,980                                    |       | 184,487           | ** ** | **28,686**            |        | 46,056 |   |
|                             | ** ** | ** **                                           |            |                                       |       |              | ** ** | ** **            |        |   |   |
| **Average Sales Prices**         |       |                                                 |            |                                       |       |              |       |                  |        |   |   |
| Gas (per Mcf)                    | ** ** | **$  6.59**                                |            | $  6.64                          |       | $  4.99 | ** ** | **$  5.28** |        | $  8.24 |   |
| Oil (per Bbl)                    | ** ** | **$63.73**                                           |            | $52.27                                     |       | $38.11            | ** ** | **$62.05**            |        | $60.80 |   |
|                             | ** ** | ** **                                           |            |                                       |       |              | ** ** | ** **            |        |   |   |
| **Revenues**                     |       |                                                 |            |                                       |       |              |       |                  |        |   |   |
| Gas sales                        | ** ** | **$**                                                | **195,130,332** |                                       | $          | 198,985,047       |       | $                     | 151,041,142 | ** ** | **$** | **39,960,899** |   | $ | 63,029,136 |   |
| Oil sales                        | ** ** | **21,190,530**                                       |            | 16,997,457                                 |       | 12,144,887        | ** ** | **5,535,750**         |        | 4,851,445 |   |
| Total Revenues                   | ** ** | **216,320,862**                                      |            | 215,982,504                                |       | 163,186,029       | ** ** | **45,496,649**        |        | 67,880,581 |   |
| ** **                       |       |                                                 |            |                                       |       |              |       |                  |        |   |   |
| **Costs**                        |       |                                                 |            |                                       |       |              |       |                  |        |   |   |
| Taxes,  transportation and other | ** ** | **20,074,451**                                       |            | 19,113,977                                 |       | 14,029,943        | ** ** | **4,838,884**         |        | 5,583,726 |   |
| Production  expense              | ** ** | **22,231,559**                                       |            | 18,468,101                                 |       | 17,893,352        | ** ** | **5,932,299**         |        | 4,979,279 |   |
| Development  costs *(c)*         | ** ** | **51,700,000**                                       |            | 39,200,000                                 |       | 21,300,000        | ** ** | **15,000,000**        |        | 15,300,000 |   |
| Overhead                         | ** ** | **8,263,357**                                        |            | 7,788,775                                  |       | 7,562,716         | ** ** | **2,141,358**         |        | 1,994,076 |   |
| Total Costs                      | ** ** | **102,269,367**                                      |            | 84,570,853                                 |       | 60,786,011        | ** ** | **27,912,541**        |        | 27,857,081 |   |
|                             | ** ** | ** **                                           |            |                                       |       |              | ** ** | ** **            |        |   |   |
| **Net Proceeds**                 | ** ** | **114,051,495**                                      |            | 131,411,651                                |       | 102,400,018       | ** ** | **17,584,108**        |        | 40,023,500 |   |
| ** **                       | ** ** | ** **                                           |            |                                       |       |              | ** ** | ** **            |        |   |   |
| **Net Profits Percentage**       | ** ** | **80%**                                              |            | 80%                                        |       | 80%               | ** ** | **80%**               |        | 80% |   |
| ** **                       | ** ** | ** **                                           | ** **      |                                       |       |              |       | ** **            | ** **  |   |   |
| **Net Profits Income**           | ** ** | **$**                                                | **91,241,196**  |                                       | $          | 105,129,321       |       | $                     | 81,920,014  | ** ** | **$** | **14,067,286** |   | $ | 32,018,800 |   |

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

*(b)*       Oil andgas sales volumes are allocated to the net profits interests based upon aformula that considers oil and gas prices and the total amount of productionexpense and development costs.  Changesin any of these factors may result in disproportionate fluctuations in volumesallocated to the net profits interests. Therefore, comparative discussion of oil and gas sales volumes is basedon the underlying properties.

*(c)*        See Note4 to Financial Statements.

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**HUGOTONROYALTY TRUST**

STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS
| ** **                                                                          | ** ** | **December 31** | ** **      |
|-------------------------------------------------------------------------------------|------------|----------------------|-----------------|
| ** **                                                                          | ** ** | **2006**             | ** **      | **2005** | ** ** |
| Assets                                                                              |       |                 |            |   |   |
|                                                                                |       |                 |            |   |   |
| Cash and  short-term investments                                                    | ** ** | **$**                | **1,813,000**   |   | $ | 13,524,280 |   |
|                                                                                | ** ** | ** **           |            |   |   |
| Net profits  interests in oil and gas properties—net  (Notes 1 and 2)          | ** ** | **163,796,772**      |            | 171,935,330 |   |
| ** **                                                                          | ** ** | **$**                | **165,609,772** |   | $ | 185,459,610 |   |
| ** **                                                                          | ** ** | ** **           |            |   |   |
| Liabilities and Trust  Corpus                                                       |       |                 |            |   |   |
|                                                                                |       |                 |            |   |   |
| Distribution  payable to unitholders                                                | ** ** | **$**                | **1,813,000**   |   | $ | 13,524,280 |   |
|                                                                                | ** ** | ** **           |            |   |   |
| Trust corpus  (40,000,000 units of beneficial interest  authorized and outstanding) | ** ** | **163,796,772**      |            | 171,935,330 |   |
|                                                                                | ** ** | ** **           |            |   |   |
| ** **                                                                          | ** ** | **$**                | **165,609,772** |   | $ | 185,459,610 |   |

 

STATEMENTS OF DISTRIBUTABLE INCOME
| ** **                                         | ** ** | **Year Ended December 31** | ** **     |
|----------------------------------------------------|------------|-------------------------------------------|----------------|
| ** **                                         | ** ** | **2006**                                  | ** **     | **2005** | ** ** | **2004** | ** ** |
| Net profits income                                 | ** ** | **$**                                     | **91,241,196** |   | $ | 105,129,321 |   | $ | 81,920,014 |   |
|                                               | ** ** | ** **                                |           |   |   |   |   |
| Interest income                                    | ** ** | **198,542**                               |           | 112,642 |   | 34,797 |   |
|                                               | ** ** | ** **                                |           |   |   |   |   |
| Total income                                       | ** ** | **91,439,738**                            |           | 105,241,963 |   | 81,954,811 |   |
|                                               | ** ** | ** **                                |           |   |   |   |   |
| Administration expense                             | ** ** | **528,978**                               |           | 410,083 |   | 357,891 |   |
|                                               | ** ** | ** **                                |           |   |   |   |   |
| Distributable  income                              | ** ** | **$**                                     | **90,910,760** |   | $ | 104,831,880 |   | $ | 81,596,920 |   |
|                                               | ** ** | ** **                                |           |   |   |   |   |
| Distributable income  per unit  (40,000,000 units) | ** ** | **$**                                     | **2.272769**   |   | $ | 2.620797 |   | $ | 2.039923 |   |

 

See Accompanying Notes to Financial Statements.

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**HUGOTONROYALTY TRUST**

STATEMENTS OF CHANGES IN TRUST CORPUS
| ** **                             | ** ** | **Year Ended December 31** | ** **      |
|----------------------------------------|------------|-------------------------------------------|-----------------|
| ** **                             | ** ** | **2006**                                  | ** **      | **2005** | ** ** | **2004** | ** ** |
| Trust corpus,  beginning of year       | ** ** | **$**                                     | **171,935,330** |   | $ | 182,551,814 |   | $ | 193,245,847 |   |
|                                   | ** ** | ** **                                |            |   |   |   |   |
| Amortization of  net profits interests | ** ** | **(8,138,558**                            | **)**           | (10,616,484 | ) | (10,694,033 | ) |
|                                   | ** ** | ** **                                | ** **      |   |   |   |   |
| Distributable  income                  | ** ** | **90,910,760**                            |            | 104,831,880 |   | 81,596,920 |   |
|                                   | ** ** | ** **                                |            |   |   |   |   |
| Distributions  declared                | ** ** | **(90,910,760**                           | **)**           | (104,831,880 | ) | (81,596,920 | ) |
|                                   | ** ** | ** **                                | ** **      |   |   |   |   |
| Trust corpus, end of  year             | ** ** | **$**                                     | **163,796,772** |   | $ | 171,935,330 |   | $ | 182,551,814 |   |

 

See Accompanying Notes to Financial Statements.

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**HugotonRoyalty Trust**

NOTES TO FINANCIAL STATEMENTS

**1.  TrustOrganization and Provisions**

Hugoton Royalty Trust wascreated on December 1, 1998 by XTO Energy Inc. (formerly known as “CrossTimbers Oil Company”).  Effective on thatdate, XTO Energy conveyed 80% net profits interests in certain predominantlygas-producing working interest properties in Kansas, Oklahoma and Wyoming tothe trust under separate conveyances for each of the three states.  In exchange for the conveyances of the netprofits interests to the trust, XTO Energy received 40 million units ofbeneficial interest in the trust.  Thetrust’s initial public offering was in April 1999.  The majority of the underlying workinginterest properties are currently owned and operated by XTO Energy (Note 6).

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

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

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

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

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

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

—                                 the trust will terminate upon the firstoccurrence of:

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

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

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

**2.  Basis of Accounting**

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

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

—         Trust expenses are recorded based on liabilities paid and cash reservesestablished by the trustee for liabilities and contingencies.

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

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

—         Net profits income is recognized in the month received rather thanaccrued in the month of production.

—         Expenses are recognized when paid rather than when incurred.

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

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

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

Theinitial carrying value of the net profits interests of $247,066,951 was XTOEnergy’s historical net book value of the interests on December 1, 1998, thedate of the transfer to the trust. Amortization of the net profits interests is calculated on a unit-of-productionbasis and charged directly to trust corpus. Accumulated amortization was $83,270,179 as of December 31, 2006 and$75,131,621 as of December 31, 2005.

**3.  Distributions toUnitholders**

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

Netprofits income received by the trustee consists of net proceeds received in theprior month by XTO Energy from the underlying properties, multiplied by80%.  Net proceeds are the gross proceedsreceived from the sale of production, less costs.  Costs generally include applicable taxes,transportation, legal and marketing charges, production expense, developmentand drilling costs, and overhead (Note 6).

XTOEnergy, as owner of the underlying properties, computes net profits incomeseparately for each of the three conveyances (one for each of the states ofKansas, Oklahoma and Wyoming).  If costsexceed revenues for any conveyance, such excess costs must be recovered, withaccrued interest, from future net proceeds of that conveyance and cannot reducenet profits income from the other conveyances.

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**4.  Development Costs**

Thefollowing summarizes actual development costs, budgeted development costsdeducted in the calculation of net profits income, and the cumulative actualcosts compared to the amount deducted:
| ** **                                                                          | ** ** | **Year Ended December 31** | ** **     |
|-------------------------------------------------------------------------------------|------------|-------------------------------------------|----------------|
| ** **                                                                          | ** ** | **2006**                                  | ** **     | **2005** | ** ** | **2004** | ** ** |
| Cumulative  actual costs (over) under the amount  deducted—beginning of period |       | **$**                                     | **113,905**    |   | $ | (319,927 | ) | $ | (1,583,988 | ) |
| Actual costs                                                                        | ** ** | **(55,224,079**                           | **)**          | (38,766,168 | ) | (20,035,939 | ) |
| Budgeted costs  deducted                                                            | ** ** | **51,700,000**                            |           | 39,200,000 |   | 21,300,000 |   |
| Cumulative actual costs  (over) under the amount  deducted—end of period       | ** ** | **$ **                               | **(3,410,174** | **)** | $  | 113,905 |   | $  | (319,927 | ) |

 

The monthly development deduction was increased twice during 2006 as aresult of increased development activity and higher costs.  The deductions were increased to $4.2 millionbeginning with the April 2006 distribution and to $5.0 million beginning withthe August 2006 distribution.  With areduction in development activity in first quarter 2007 and based on thedevelopment budget for 2007, the development cost deduction was lowered to$3.75 million beginning with the February 2007 distribution.  XTO Energy has advised the trustee that thismonthly deduction will continue to be evaluated and revised as necessary.

**5.  FederalIncome Taxes**

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

For federal income tax purposes, unitholders of a grantor trust areconsidered to own the trust’s income and principal as though no trust were inexistence.  The income of the trust isdeemed to be received or accrued by the unitholders at the time such income isreceived or accrued by the trust, rather than when distributed by the trust.

**6.  XTO EnergyInc.**

XTO Energy operates approximately 94% of the underlyingproperties.  In computing net proceeds,XTO Energy deducts an overhead charge for reimbursement of administrativeexpenses on the underlying properties it operates.  As of December 31, 2006, the overhead chargewas approximately $716,000 ($572,800 net to the trust) per month and is subjectto annual adjustment based on an oil and gas industry index as defined in thetrust agreement.

In April and May 1999, XTO Energy sold 17 million trust units in thetrust’s initial public offering, and later in 1999 and 2000, sold 1.3 milliontrust units to certain of its officers. The trust did not receive any proceeds from the sale of trustunits.  In May 2006, XTO Energydistributed all of its remaining 21.7 million trust units as a dividend to itscommon stockholders.  XTO Energycurrently is not a unitholder of the trust. In January 2006, XTO Energy announced that it would consider selling theunderlying properties.  However, XTOEnergy advised the trustee in August 2006, that after a full review, it hasdecided to retain ownership of these underlying property interests at thistime.

XTO Energy sells a significant portion of natural gas production fromthe underlying properties to certain of XTO Energy’s wholly owned subsidiariesunder contracts in existence when the trust was created, generally at amountsapproximating monthly published market prices. Most of the production from the Hugoton area is sold under a contract toTimberland Gathering & Processing Company, Inc. (“TGPC”) based on the indexprice.  Much of the gas production inMajor County, Oklahoma is sold to Ringwood Gathering Company (“RGC”), whichretains approximately $0.31 per Mcf compression and gathering fee.  TGPC and RGC sell gas to Cross Timbers

16

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Energy Services, Inc. (“CTES”), which markets gas to thirdparties.  XTO Energy sells directly toCTES most gas production not sold directly to TGPC or RGC.

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

**7. Contingencies**

*Litigation*

On October 17, 1997, an action, styled *UnitedStates of America ex rel. Grynberg v. Cross Timbers Oil Company, et al.*,was filed in the United States District Court for the Western District ofOklahoma by Jack J. Grynberg on behalf of the United States under the *qui tam* provisions of the U.S. FalseClaims Act against XTO Energy.  Theplaintiff alleges that XTO Energy underpaid royalties on natural gas producedfrom federal leases and lands owned by Native Americans in amounts in excess of20% as a result of mismeasuring the volume of natural gas, incorrectlyanalyzing its heating content and improperly valuing the natural gas during atleast the past ten years.  The plaintiffseeks treble damages for the unpaid royalties (with interest, attorney’s feesand expenses), civil penalties between $5,000 and $10,000 for each violation ofthe U.S. False Claims Act, and an order for XTO Energy to cease the allegedlyimproper measuring practices.  Thislawsuit against XTO Energy and similar lawsuits filed by Grynberg against morethan 300 other companies have been consolidated in the United States DistrictCourt for Wyoming.  In October 2002, thecourt granted a motion to dismiss Grynberg’s royalty valuation claims, andGrynberg’s appeal of this decision was dismissed for lack of appellatejurisdiction in May 2003.  In response toa motion to dismiss filed by XTO Energy and other defendants in October 2006,the district judge held that Grynberg failed to establish the jurisdictionalrequirements to maintain the action against XTO Energy and other defendants anddismissed the actions for lack of subject matter jurisdiction.  Grynberg has filed an appeal of thisdecision.  While XTO Energy is unable topredict the final outcome of this case or estimate the amount of any possibleloss, it has informed the trustee that it believes that the allegations of thislawsuit are without merit and intends 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 by royaltyowners of natural gas wells in Oklahoma. The plaintiffs allege that XTO Energy has not properly accounted to theplaintiffs for the royalties to which they are entitled and seek an accountingregarding the natural gas and other products produced from their wells and theprices paid for the natural gas and other products produced, and for payment ofthe monies allegedly owed since June 2002, with a certain limited number ofplaintiffs claiming monies owed for additional time.  A hearing on the class certification has notbeen scheduled.  The plaintiffs have notstated an amount they are seeking.  XTOEnergy has informed the trustee that it believes that it has strong defenses tothis lawsuit and intends to vigorously defend its position.  However, if XTO Energy ultimately makes anysettlement payments, the trust will bear its 80% share of such settlementrelated to production from the underlying properties.  Additionally, if a judgment or settlementincreases the amount of future payments to royalty owners, the trust would bearits proportionate share of the increased payments through reduced netproceeds.  XTO Energy has informed thetrustee that, although the amount of any reduction in net proceeds is notpresently determinable, in its management’s opinion, the amount is notcurrently expected to be material to the trust’s annual distributable income,financial position or liquidity.

Certain of the underlying properties are involved in various otherlawsuits and certain governmental proceedings arising in the ordinary course ofbusiness. XTO Energy has advised the trustee that it does not believe

17

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that the ultimate resolution of these claims will have a materialeffect on trust annual distributable income, financial position or liquidity.

*Other*

Several states have enacted legislation to require state income taxwithholding from nonresident recipients 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 to change by the various states, whichcould 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.

**8.  SupplementalOil and Gas Reserve Information (Unaudited)**

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

**9.  QuarterlyFinancial Data (Unaudited)**

The following is a summary of net profits income, distributable incomeand distributable income per unit by quarter for 2006 and 2005:
| ** **          | ** ** | ** **           | ** **     | ** **        | ** ** | **Distributable** | ** ** |
|---------------------|------------|----------------------|----------------|-------------------|------------|-------------------|------------|
| ** **          | ** ** | **Net Profits** | ** **     | **Distributable** | ** ** | **Income**        | ** ** |
| ** **          | ** ** | **Income**           | ** **     | **Income**        | ** ** | **per Unit** | ** ** |
| **2006**            |       |                 |           |              |       |              |       |
| **First Quarter**   | ** ** | **$**                | **39,085,894** | ** **        | **$**      | **39,041,600**    | ** ** | **$** | **0.976040** | ** ** |
| **Second  Quarter** | ** ** | **21,125,072**       | ** **     | **20,972,240**    | ** ** | **0.524306**      | ** ** |
| **Third  Quarter**  | ** ** | **16,962,944**       | ** **     | **16,920,800**    | ** ** | **0.423020**      | ** ** |
| **Fourth  Quarter** | ** ** | **14,067,286**       | ** **     | **13,976,120**    | ** ** | **0.349403**      | ** ** |
| ** **          | ** ** | **$**                | **91,241,196** | ** **        | **$**      | **90,910,760**    | ** ** | **$** | **2.272769** | ** ** |
|                |       |                 |           |              |       |              |       |
| 2005                |       |                 |           |              |       |              |       |
| First Quarter       |       | $                    | 25,818,940     |              | $          | 25,698,160        |       | $ | 0.642454 |   |
| Second Quarter      |       | 22,965,660           |           | 22,832,040        |       | 0.570801          |       |
| Third Quarter       |       | 24,325,921           |           | 24,304,200        |       | 0.607605          |       |
| Fourth Quarter      |       | 32,018,800           |           | 31,997,480        |       | 0.799937          |       |
|                |       | $                    | 105,129,321    |              | $          | 104,831,880       |       | $ | 2.620797 |   |

 

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**REPORT OFINDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM**

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

We have audited the accompanying statements of assets, liabilities andtrust corpus of the Hugoton Royalty Trust as of December 31, 2006 and 2005, andthe related statements of distributable income and changes in trust corpus foreach of the years in the three-year period ended December 31, 2006.  These financial statements are theresponsibility of the trustee. Our responsibility is to express an opinion onthese financial statements based on our audits.

We conducted our audits in accordance with the standards of the PublicCompany Accounting Oversight Board (United States).  Those standards require that we plan andperform the audit to obtain reasonable assurance about whether the financialstatements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting theamounts and disclosures in the financial statements. An audit also includesassessing the accounting principles used and significant estimates made by thetrustee, and evaluating the overall financial statement presentation.  We believe that our audits provide areasonable basis for our opinion.

As described in Note 2 to the financial statements, these financialstatements have been prepared on the modified cash basis of accounting, whichis a comprehensive basis of accounting other than accounting principlesgenerally accepted in the United States of America.

In our opinion, the financial statements referred to above presentfairly, in all material respects, the assets, liabilities, and trust corpus ofthe Hugoton Royalty Trust as of December 31, 2006 and 2005 and itsdistributable income and changes in trust corpus for each of the years in thethree-year period ended December 31, 2006 in conformity with the modified cashbasis of accounting described in Note 2.

We also have audited, in accordance with the standards of the PublicCompany Accounting Oversight Board (United States), the effectiveness of the HugotonRoyalty Trust’s internal control over financial reporting as of December 31,2006, based on criteria established in *InternalControl—Integrated Framework* issued by the Committee of SponsoringOrganizations of the Treadway Commission (COSO), and our report dated February28, 2007 expressed an unqualified opinion on the trustee’s assessment of, andthe effective operation of, internal control over financial reporting.

KPMG LLP

Dallas, TexasFebruary 28, 2007

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**REPORT OFINDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM**

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

We have audited the trustee’s assessment, included in Trustee’s Reporton Internal Control over Financial Reporting under Item 9A of the accompanyingAnnual Report on Form 10-K, that the Hugoton Royalty Trust maintained effectiveinternal control over financial reporting as of December 31, 2006, based oncriteria established in *InternalControl—Integrated Framework* issued by the Committee of SponsoringOrganizations of the Treadway Commission (COSO).  The trustee of the Hugoton Royalty Trust isresponsible for maintaining effective internal control over financial reportingand for its assessment of the effectiveness of internal control over financialreporting. Our responsibility is to express an opinion on the trustee’sassessment and an opinion on the effectiveness of the trust’s internal controlover financial reporting based on our audit.

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

The trust’s internal control over financial reporting is a processdesigned to provide reasonable assurance regarding the reliability of financialreporting and the preparation of financial statements for external purposes inaccordance with the modified cash basis of accounting.  The trust’s internal control over financialreporting includes those policies and procedures that: (1) pertain to the maintenanceof records that, in reasonable detail, accurately and fairly reflect thetransactions and dispositions of the assets of the trust; (2) providereasonable assurance that transactions are recorded as necessary to permitpreparation of financial statements in accordance with the modified cash basisof accounting, and that receipts and expenditures of the trust are being madeonly in accordance with authorizations of the trustee; and (3) providereasonable assurance regarding prevention or timely detection of unauthorizedacquisition, use, or disposition of the trust’s assets that could have amaterial effect on the financial statements.

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

In our opinion, the trustee’s assessment that the Hugoton Royalty Trustmaintained effective internal control over financial reporting as of December31, 2006, is fairly stated, in all material respects, based on criteriaestablished in *Internal Control—Integrated**Framework* issued by COSO. Also, in our opinion, the Hugoton Royalty Trust maintained, in allmaterial respects, effective internal control over financial reporting as ofDecember 31, 2006, based on criteria established in *InternalControl—Integrated Framework* issued by COSO.

We also have audited, in accordance with the standards of the PublicCompany Accounting Oversight Board (United States), the statements of assets,liabilities, and trust corpus of the Hugoton Royalty Trust as of December 31,2006 and 2005, and the related statements of distributable income and changesin trust corpus for each of the years in the three-year period

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endedDecember 31, 2006, and our report dated February 28, 2007 expressed anunqualified opinion on those financial statements and included an explanatoryparagraph that described the trust’s method of accounting as explained in Note2 to the financial statements.

KPMGLLP

Dallas, TexasFebruary 28, 2007

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**HUGOTON ROYALTY TRUST**

901 Main Street, 17th Floor P.O. Box 830650 Dallas, Texas 75283-0650 (877) 228-5083 Bank of America, N.A., Trustee

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

**WEB SITE**

www.hugotontrust.com

**AUDITORS**

KPMG LLPDallas, Texas

**LEGAL COUNSEL**

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

**TAX COUNSEL**

Winstead Sechrest & Minick P.C.Houston, Texas

**TRANSFER AGENT AND REGISTRAR**

Mellon Investor Services, L.L.C.www.melloninvestor.com

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