10-K

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

 

FORM 10-K

 

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

For the fiscal year ended December 31, 2008

Commission file number 1-10476

HUGOTON ROYALTY TRUST

(Exact Name of Registrant as Specified in the Hugoton Royalty Trust Indenture)

Texas	58-6379215
(State or Other Jurisdiction of Incorporation or Organization)	(I.R.S. Employer Identification No.)

U.S. Trust, Bank of America
Private Wealth Management
Trustee
P.O. Box 830650
Dallas, Texas 75283-0650

(Address of Principal Executive Offices) (Zip Code)

(877) 228-5083

(Registrant’s Telephone Number, Including Area Code)

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

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

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

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

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

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

Large accelerated filer x	Accelerated filer o
Non-accelerated filer o (Do not check if a smaller reporting company)	Smaller reporting company o

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

The aggregate market value of the units of beneficial interest of the trust, based on the closing price on the New York Stock Exchange as of June 30, 2008 (the last business day of its most recently completed second fiscal quarter), held by non-affiliates of the registrant on that date was approximately $1.4 billion.

At February 25, 2009, there were 40,000,000 units of beneficial interest of the trust outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

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

2008 Annual Report to Unitholders – Part II

PART I

Item 1. Business

Hugoton Royalty Trust is an express trust created under the laws of Texas pursuant to the Hugoton Royalty Trust Indenture entered into on December 1, 1998 between XTO Energy Inc. (formerly known as Cross Timbers Oil Company), as grantor, and NationsBank, N.A., as trustee. Bank of America, N.A., successor to NationsBank, N.A., is now the trustee of the trust. In 2007 the Bank of America private wealth management group officially became known as “U.S. Trust, Bank of America Private Wealth Management.” The legal entity that serves as the trustee of the trust did not change, and references in this Form 10-K to U.S. Trust, Bank of America Private Wealth Management shall describe the legal entity Bank of America, N.A. The principal office of the trust is located 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-K and all amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934. These reports are accessible through our internet web site as soon as reasonably practicable after we electronically file such material with, or furnish it to, the Securities and Exchange Commission.

Effective December 1, 1998, XTO Energy conveyed to the trust 80% net profits interests in certain predominantly natural gas producing working interest properties in Kansas, Oklahoma and Wyoming under three separate conveyances. In exchange for these net profits interest conveyances to the trust, 40 million units of beneficial interest were issued to XTO Energy. In April and May 1999, XTO Energy sold a total of 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. The trust did not receive the proceeds from these sales of trust units. Units are listed and traded on the New York Stock Exchange under the symbol “HGT.”

In May 2006, XTO Energy distributed all of its remaining 21.7 million trust units as a dividend to its common stockholders. XTO Energy currently is not a unitholder of the trust.

The net profits interests entitle the trust to receive 80% of the net proceeds from the sale of oil and gas from the underlying properties. Each month XTO Energy determines the amount of cash received from the sale of production and deducts property and production taxes, production expense, development costs and overhead.

Net proceeds payable to the trust depend upon production quantities, sales prices of oil and gas and costs to develop and produce oil and gas in the prior month. If monthly costs exceed revenues for any of the three conveyances (one for each of the states of Kansas, Oklahoma and Wyoming), such excess costs must be recovered, with accrued interest, from future net proceeds of that conveyance and cannot reduce net proceeds from other conveyances.

In November 2008 and November and December of 2007, costs exceeded revenues on properties underlying the Wyoming net profits interests. For further information on excess costs, see “Trustee’s Discussion and Analysis” of financial condition and results of operations for the three-year period ended December 31, 2008 in the trust’s annual report to unitholders for the year ended December 31, 2008.

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

As a working interest owner, XTO Energy can generally decline participation in any operation and allow consenting parties to conduct such operations, as provided under the operating agreements. XTO Energy also can assign, sell, or otherwise transfer its interest in the underlying properties, subject to the net profits interests, or can abandon an underlying property if it is incapable of producing in paying quantities, as determined by XTO Energy.

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

Net profits income received by the trust on or before the last business day of the month is related to net proceeds received by XTO Energy in the preceding month, and is generally attributable to oil and gas production two months prior. The amount to be distributed to unitholders each month by the trustee is determined by:

Adding – 

(1) net profits income received,
(2) interest income and any other cash receipts and
(3) cash available as a result of reduction of cash reserves, then

Subtracting – 

(1) liabilities paid and
(2) the reduction in cash available related to establishment of or increase in any cash reserve.

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

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

The trustee’s function is to collect the net profits income from the net profits interests, to pay all trust expenses, and pay the monthly distribution amount to unitholders. The trustee’s powers are specified by the terms of the trust indenture. The trust cannot engage in any business activity or acquire any assets other than the net profits interests and specific short-term cash investments. The trust has no employees since all administrative functions are performed by the trustee.

Approximately 85% of the net profits income received by the trust during 2008, as well as 92% of the estimated proved reserves of the net profits interests at December 31, 2008 (based on estimated future net cash flows using year-end oil and gas prices), is attributable to natural gas. There has historically been a greater demand for gas during the winter months than the rest of the year. Otherwise, trust income generally is not subject to seasonal factors, nor dependent upon patents, licenses, franchises or concessions. The trust conducts no research activities.

Item 1A. Risk Factors

The following factors, among others, could cause actual results to differ materially from those contained in forward-looking statements made in this report and presented elsewhere by the trustee from time to time. Such factors, among others, may have a material adverse effect upon the trust’s financial condition, distributable income and changes in trust corpus.

The following discussion of risk factors should be read in conjunction with the financial statements and related notes included in the trust’s annual report to unitholders for the year ended December 31, 2008. Because of these and other factors, past financial performance should not be considered an indication of future performance.

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

The public trading price for the trust units tends to be tied to the recent and expected levels of cash distributions on the trust units. The amounts available for distribution by the trust vary in response to numerous factors outside the control of the trust or XTO Energy, including prevailing prices for oil and natural gas produced from the underlying properties. The market price of the trust units is not necessarily indicative of the value that the trust would realize if the net profits interests were sold to a third party buyer. In addition,

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such market price is not necessarily reflective of the fact that, since the assets of the trust are depleting assets, a portion of each cash distribution paid on the trust units should be considered by investors as a return of capital, with the remainder being considered as a return on investment. There is no guarantee that distributions made to a unitholder over the life of these depleting assets will equal or exceed the purchase price paid by the unitholder.

Oil and natural gas prices fluctuate due to a number of uncontrollable factors, and any decline will adversely affect the net proceeds payable to the trust and trust distributions.

The trust’s monthly cash distributions are highly dependent upon the prices realized from the sale of natural gas and, to a lesser extent, oil. Oil and natural gas prices can fluctuate widely on a month-to-month basis in response to a variety of factors that are beyond the control of the trust and XTO Energy. Factors that contribute to price fluctuations include instability in oil-producing regions, worldwide economic conditions, weather conditions, the supply and price of domestic and foreign oil and natural gas, consumer demand, the price and availability of alternative fuels, the proximity to, and capacity of, transportation facilities and the effect of worldwide energy conservation measures. Moreover, government regulations, such as regulation of natural gas transportation and price controls, can affect product prices in the long term. Lower oil and natural gas prices may reduce the amount of oil and natural gas that is economic to produce and will reduce net profits available to the trust. The volatility of energy prices reduces the predictability of future cash distributions to trust unitholders.

Higher production expense and/or development costs, without concurrent increases in revenue, will directly decrease the net proceeds payable to the trust.

Production expense and development costs are deducted in the calculation of the trust’s share of net proceeds. Accordingly, higher or lower production expense and development costs, without concurrent changes in revenue, will directly decrease or increase the amount received by the trust. If development costs and production expense for underlying properties in a particular state exceed the production proceeds from the properties (as was the case with respect to the properties underlying the Wyoming net profits interests in November and December 2007 and November 2008), the trust will not receive net proceeds for those properties until future proceeds from production in that state exceed the total of the excess costs plus accrued interest during the deficit period. Development activities may not generate sufficient additional revenue to repay the costs.

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

Estimating proved oil and gas reserves is inherently uncertain. Petroleum engineers consider many factors and make assumptions in estimating reserves and future net cash flows. Those factors and assumptions include historical production from the area compared with production rates from similar producing areas, the effects of governmental regulation, assumptions about future commodity prices, production expense and development costs, taxes and capital expenditures, the availability of enhanced recovery techniques and relationships with landowners, working interest partners, pipeline companies and others. Lower oil and gas prices generally cause lower estimates of proved reserves. Ultimately, actual production, revenues and expenditures for the underlying properties will vary from estimates and those variances could be material. Because the trust owns net profits interests, it does not own a specific percentage of the oil and gas reserves. Estimated proved reserves for the net profits interests are based on estimates of reserves for the underlying properties and an allocation method that considers estimated future net proceeds and oil and gas prices. Increases or decreases in oil and gas prices can significantly affect estimated reserves of the net profits interests.

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

There are operational risks and hazards associated with the production and transportation of oil and natural gas, including without limitation natural disasters, blowouts, explosions, fires, leakage of oil or natural gas, releases of other hazardous materials, mechanical failures, cratering, and pollution. Any of these or similar occurrences could result in the interruption or cessation of operations, personal injury or loss of life,

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property damage, damage to productive formations or equipment, damage to the environment or natural resources, or cleanup obligations. The operation of oil and gas properties is also subject to various laws and regulations. Non-compliance with such laws and regulations could subject the operator to additional costs, sanctions or liabilities. The uninsured costs resulting from any of the above or similar occurrences could be deducted as a production expense or development cost in calculating the net proceeds payable to the trust, and would therefore reduce trust distributions by the amount of such uninsured costs.

Cash held by the trustee is not fully insured by the Federal Deposit Insurance Corporation, and future royalty income may be subject to risks relating to the creditworthiness of third parties.

Currently, cash held by the trustee as a reserve for liabilities and for the payment of expenses and distributions to unitholders is invested in Bank of America certificates of deposit which are backed by the good faith of Bank of America, N.A., but are only insured by the Federal Deposit Insurance Corporation up to $250,000. The trust does not lend money and has limited ability to borrow money, which the trustee believes limits the trust’s risk from the current tightening of credit markets. The trust’s future royalty income, however, may be subject to risks relating to the creditworthiness of the operators of the underlying properties and other purchasers of the crude oil and natural gas produced from the underlying properties, as well as risks associated with fluctuations in the price of crude oil and natural gas.

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

Neither the trustee nor the trust unitholders can influence or control the operation or future development of the underlying properties. The failure of an operator to conduct its operations or discharge its obligations in a proper manner could have an adverse effect on the net proceeds payable to the trust. Although XTO Energy and other operators of the underlying properties must adhere to the standard of a prudent operator, they are under no obligation to continue operating the properties. Neither the trustee nor trust unitholders have the right to replace an operator.

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

The net proceeds payable to the trust are derived from the sale of depleting assets. Eventually, the properties underlying the trust’s net profits interests will cease to produce in commercial quantities and the trust will, therefore, cease to receive any net proceeds therefrom. The reduction in proved reserve quantities is a common measure of the depletion. Future maintenance and development projects on the underlying properties will affect the quantity of proved reserves. The timing and size of these projects will depend on the market prices of oil and natural gas. If XTO Energy or other operators of the properties do not implement additional maintenance and successful development projects, the future rate of production decline of proved reserves may be higher than the rate currently estimated.

Terrorism and continued geopolitical hostilities could adversely affect trust distributions or the market price of the trust units.

Terrorist attacks and the threat of terrorist attacks, whether domestic or foreign, as well as the military or other actions taken in response, cause instability in the global financial and energy markets. Terrorism and other geopolitical hostilities could adversely affect trust distributions or the market price of the trust units in unpredictable ways, including through the disruption of fuel supplies and markets, increased volatility in oil and natural gas prices, or the possibility that the infrastructure on which the operators of the underlying properties rely could be a direct target or an indirect casualty of an act of terror.

XTO Energy may transfer its interest in the underlying properties without the consent of the trust or the trust unitholders.

XTO Energy may at any time transfer all or part of its interest in the underlying properties to another party. Neither the trust nor the trust unitholders are entitled to vote on any transfer of the properties underlying the trust’s net profits interests, and the trust will not receive any proceeds of any such transfer. Following

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any transfer, the transferred property will continue to be subject to the net profits interests of the trust, but the calculation, reporting and remitting of net proceeds to the trust will be the responsibility of the transferee.

XTO Energy or any other operator of any underlying property may abandon the property, thereby terminating the related net profits interest payable to the trust.

XTO Energy or any other operator of the underlying properties, or any transferee thereof, may abandon any well or property without the consent of the trust or the trust unitholders if they reasonably believe that the well or property can no longer produce in commercially economic quantities. This could result in the termination of the net profits interest relating to the abandoned well or property.

The net profits interests can be sold and the trust would be terminated.

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

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

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

The trust indenture and related trust law permit the trustee and the trust to sue XTO Energy or any other operators of the underlying properties to compel them to fulfill the terms of the conveyance of the net profits interests. If the trustee does not take appropriate action to enforce provisions of the conveyance, the recourse of the trust unitholders would likely be limited to bringing a lawsuit against the trustee to compel the trustee to take specified actions. Trust unitholders probably would not be able to sue XTO Energy or any other operators of the underlying properties.

Financial information of the trust is not prepared in accordance with U.S. GAAP.

The financial statements of the trust are prepared on a modified cash basis of accounting, which is a comprehensive basis of accounting other than U.S. generally accepted accounting principles, or U.S. GAAP. Although this basis of accounting is permitted for royalty trusts by the Securities and Exchange Commission, the financial statements of the trust differ from U.S. GAAP financial statements because net profits income is not accrued in the month of production, expenses are not recognized when incurred and cash reserves may be established for certain contingencies that would not be recorded in U.S. GAAP financial statements.

The limited liability of trust unitholders is uncertain.

The trust unitholders are not protected from the liabilities of the trust to the same extent that a shareholder would be protected from a corporation’s liabilities. The structure of the trust does not include the interposition of a limited liability entity such as a corporation or limited partnership which would provide further limited liability protection to trust unitholders. While the trustee is liable for any excess liabilities incurred if the trustee fails to insure that such liabilities are to be satisfied only out of trust assets, under the laws of Texas, which are unsettled on this point, a unitholder may be jointly and severally liable for any liability of the trust if the satisfaction of such liability was not contractually limited to the assets of the trust and the assets 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 the underlying properties.

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

Drilling oil and natural gas wells involves numerous risks, including the risk that commercially productive oil and natural gas reservoirs are not encountered. The presence of unanticipated pressures or irregularities

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in formations, miscalculations or accidents may cause drilling activities to be unsuccessful. In addition, there is often uncertainty as to the future cost or timing of drilling, completing and operating wells. Further, development activities may be curtailed, delayed or canceled as a result of a variety of factors, including:

• unexpected drilling conditions;

• title problems;

• restricted access to land for drilling or laying pipeline;

• pressure or irregularities in formations;

• equipment failures or accidents;

• adverse weather conditions; and

• costs of, or shortages or delays in the availability of, drilling rigs, tubular materials and equipment.

While these risks do not expose the trust to liabilities of the drilling contractor or operator of the well, they can reduce net proceeds payable to the trust and trust distributions by decreasing oil and gas revenues or increasing production expense or development costs from the underlying properties. Furthermore, these risks may cause the costs of development activities on the underlying properties to exceed the revenues therefrom, thereby reducing net proceeds payable to the trust and trust distributions.

The underlying properties are subject to complex federal, state and local laws and regulations that could adversely affect net proceeds payable to the trust and trust distributions.

Extensive federal, state and local regulation of the oil and natural gas industry significantly affects operations on the underlying properties. In particular, oil and natural gas development 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 other related facilities, which costs could reduce net proceeds payable to the trust and trust distributions. These regulations may become more demanding in the future.

Item 1B. Unresolved Staff Comments

As of December 31, 2008, the trust did not have any unresolved Securities and Exchange Commission staff comments.

Item 2. Properties

The net profits interests are the principal asset of the trust. The trustee cannot acquire any other assets, with the exception of certain short-term investments as specified under Item 1. The trustee may sell or otherwise dispose of all or any part of the net profits interests if approved 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 profits interests in any calendar year, pursuant to notice from XTO Energy of its desire to sell the related underlying properties. Any such sale must be for cash with the proceeds promptly distributed to the unitholders. The underlying properties are predominantly natural gas producing leases located in the states of Kansas, Oklahoma and Wyoming. The principal productive areas are the Hugoton area, Anadarko Basin and Green River Basin.

All the underlying properties are currently owned by XTO Energy. XTO Energy may sell all or any portion of the underlying properties at any time, subject to and burdened by the net profits interests.

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 natural gas producing areas. During 2008, daily sales volumes from the underlying properties in the Hugoton area averaged approximately 20,900 Mcf of gas and 69 Bbls of oil.

Most of the production from the underlying properties in the Hugoton area is from the Chase formation. XTO Energy has informed the trustee that it plans to develop other formations that underlie the 79,500 net

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acres held by production by the Chase formation wells, which include the Council Grove, Morrow, Chester and St. Louis formations. These formations are characterized by both oil and gas production from a variety of structural and stratigraphic traps. Since 2003, XTO Energy has drilled wells to these formations and plans to continue this development program in 2009.

Within this area, XTO Energy performed 13 workovers in 2008, of which 2 were Chase restimulations. XTO Energy has informed the trustee that it does not plan to drill any new wells and will perform up to 16 workovers during 2009.

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

• additional compression to lower line pressures,

• installing artificial lift,

• opening new producing zones in existing wells,

• restimulating producing intervals in existing wells utilizing new technology,

• deepening existing wells to new producing zones, and

• drilling additional wells.

XTO Energy delivers most of its Hugoton gas production to a gathering and processing system operated by a subsidiary. This system collects approximately 72% of its throughput from underlying properties, which, in recent months, has been approximately 15,200 Mcf per day from 252 wells. The gathering subsidiary purchases the gas from XTO Energy at the wellhead, gathers and transports the gas to its plant, and treats and processes the gas at the plant. The gathering subsidiary pays XTO Energy for wellhead volumes at a price of 80% to 85% of the net residue price received by XTO Energy’s marketing affiliate. This affiliate currently sells the residue to a pipeline at a price based on a monthly pipeline index less actual fees.

Other Hugoton gas production is sold under a third party contract. Under the contract, XTO Energy receives 74.5% of the net proceeds received from the sale of the residue gas and liquids.

Anadarko Basin

Oil and gas accumulations were discovered in the Anadarko Basin of western Oklahoma in 1945. XTO Energy is one of the largest producers in the Ringwood, Northwest Okeene and Cheyenne Valley fields of Major County, the Northeast Cedardale field of Woodward County and the Elk City field of Beckham County, the principal producing regions of the underlying properties in the Anadarko Basin. Daily sales volumes from the underlying properties in the Anadarko Basin averaged 35,500 Mcf of gas and 822 Bbls of oil in 2008.

The fields in the Major County area are characterized by oil and gas production from a variety of structural and stratigraphic traps. Productive zones include the Oswego, Red Fork, Inola, Chester, Manning, Mississippian, Hunton and Arbuckle formations. Within this area, XTO Energy drilled 16 gross (10.6 net) wells and performed 28 workovers in 2008. XTO Energy has informed the trustee that it plans to drill up to 8 wells and perform up to 10 workovers in Major County during 2009.

The fields within Woodward County are characterized primarily by gas production from a variety of structural and stratigraphic traps. Productive zones and include the Cottage Grove, Oswego, Chester and Mississippian formations. Within this area, XTO Energy drilled 11 gross (8.7 net) wells and performed 5 workovers in 2008. XTO Energy has informed the trustee that it plans to drill up to 8 wells and perform up to 4 workovers in Woodward County during 2009.

The Elk City field on the eastern edge of Beckham County produces oil and gas from a structural anticline with stratigraphic trapping features. Production zones include the Hoxbar, Atoka and Morrow formations. Within this area, XTO Energy drilled 1 gross (0.9 net) wells and performed 7 workovers in 2008. XTO Energy has informed the trustee that it does not plan to drill any new wells and will perform 3 workovers within the Elk City field during 2009.

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XTO Energy plans to further develop the underlying properties in the Anadarko Basin primarily through:

• mechanical stimulation of existing wells,

• installing artificial lift,

• opening new producing zones in existing wells,

• deepening existing wells to new producing zones, and

• drilling additional wells.

A gathering subsidiary of XTO Energy operates a 300-mile gathering system and pipeline in the Major County area. The gathering subsidiary and a third-party processor purchase natural gas produced at the wellhead from XTO Energy and other producers in the area under various agreements including life-of-production contracts. The gathering subsidiary gathers and transports the gas to a third-party processor, which processes the gas and pays XTO Energy and other producers for at least 50% of the liquids processed. After the gas is processed, the gathering subsidiary transports the gas via a residue pipeline to a connection with an interstate pipeline. The gathering subsidiary sells the residue gas to the marketing subsidiary of XTO Energy based upon a published index price. The gathering subsidiary pays this price to XTO Energy less a compression and gathering fee of approximately $0.31 per Mcf of residue gas. This gathering fee was previously approved by the Federal Energy Regulatory Commission when the gathering subsidiary was regulated. During 2008, the gathering system collected approximately 12,500 Mcf per day from 320 wells, approximately 50% of which XTO Energy operates. Estimated capacity of the gathering system is 28,000 Mcf per day. The gathering subsidiary also provides contract operating services to properties in Woodward County, collecting approximately 11,300 Mcf per day from 127 wells, for an average fee of approximately $0.05 per Mcf.

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

Green River Basin

The Green River Basin is located in southwestern Wyoming. Natural gas was discovered in the Fontenelle Field of the Green River Basin in the early 1970s. The producing reservoirs are the Frontier, Baxter and Dakota sandstones.

Daily 2008 sales volumes from the underlying properties in the Fontenelle Field averaged 20,600 Mcf of natural gas and 43 Bbls of oil. In 2008, XTO Energy completed 7 gross (7.0 net) wells and performed 9 workovers. XTO Energy has advised the trustee that it does not plan to drill any new wells and will perform up to 6 workovers in the Green River Basin during 2009. XTO Energy has advised the trustee that it is continuing its efforts to reduce pipeline pressure which has shown potential for increasing production and extending field life in the Fontenelle Field.

Potential development activities for the underlying properties in this area include:

• installing artificial lift,

• restimulating producing intervals utilizing new technology,

• additional compression to lower line pressures, and

• opening new producing zones in existing wells.

XTO Energy markets the gas produced from the Fontenelle Unit and nearby properties under three different marketing arrangements. Under the agreement covering approximately 70% of the gas sold, XTO Energy compresses the gas on the lease, transports it off the lease and compresses the gas again prior to entry into the gas plant pipeline. The pipeline transports the gas to the gas plant, where the gas is processed, then redelivered to XTO Energy. The owner of the gas plant and related pipeline charges XTO Energy for operational fuel and processing. In 2008, the fuel charge was 1.86% of the volumes produced and the processing fee was approximately $0.11 per MMBtu. XTO Energy transports and sells this gas directly to the markets based on a

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spot sales price. The gas not sold under the above arrangement is sold either under a similar arrangement where the fee is $0.17 per MMBtu, or under a contract where XTO Energy directly sells the gas to a third party on the lease at an adjusted index price. Condensate is sold at the lease to an independent third party at market rates.

Producing Acreage and Well Counts

For the following data, “gross” refers to the total wells or acres on the underlying properties in which XTO Energy owns a working interest and “net” refers to gross wells or acres multiplied by the percentage working interest owned by XTO Energy. Although many of XTO Energy’s wells produce both oil and gas, a well is categorized as an oil well or a gas well based upon the ratio of oil to natural gas production. Operated wells are managed by XTO Energy, while nonoperated wells are managed by others.

The underlying properties are interests in developed properties located primarily in gas producing regions of Kansas, Oklahoma and Wyoming. The following is a summary of the approximate producing acreage of the underlying properties at December 31, 2008. Undeveloped acreage is not significant.

	Gross		Net
Hugoton Area		217,590		200,390
Anadarko Basin		151,402		113,436
Green River Basin		39,644		27,333
Total		408,636		341,159

The following is a summary of the producing wells on the underlying properties as of December 31, 2008:

	Operated Wells				Nonoperated Wells				Total
	Gross		Net		Gross		Net		Gross		Net
Gas		1,274		1,130.7		304		70.0		1,578		1,200.7
Oil		48		42.1		8		1.4		56		43.5
Total		1,322		1,172.8		312		71.4		1,634		1,244.2

The following is a summary of the number of wells drilled on the underlying properties during the years indicated. Unless otherwise indicated, all wells drilled are developmental. There were 7 gross (4.3 net) wells in process of drilling at December 31, 2008.

	2008				2007				2006
	Gross		Net		Gross		Net		Gross		Net
Completed gas wells		54		35.0		51		30.4		44		28.8
Completed oil wells		1		0.1		—		—		3		0.6
Non-productive wells		—		—		—		—		1		0.1
Total(a)		55		35.1		51		30.4		48		29.5

(a) Included in totals are 14 gross (2.6 net) wells in 2008, 17 gross (4.3 net) wells in 2007 and 17 gross (4.3 net) wells in 2006, drilled on nonoperated interests.

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Oil and Natural Gas Production

Trust production is recognized in the period net profits income is received, which is the month following receipt by XTO Energy, and generally two months after the time of production. Oil and gas production and average sales prices attributable to the underlying properties and the net profits interests for the three years ended December 31, 2008 were as follows:

	2008		2007		2006
Production
Underlying Properties
Gas – Sales (Mcf)		28,176,094		28,092,224		29,628,079
Average per day (Mcf)		76,984		76,965		81,173
Oil – Sales (Bbls)		341,754		305,594		332,525
Average per day (Bbls)		934		837		911
Net Profits Interests
Gas – Sales (Mcf)		13,134,564		11,233,503		12,871,453
Average per day (Mcf)		35,887		30,777		35,264
Oil – Sales (Bbls)		169,915		140,805		145,230
Average per day (Bbls)		464		386		398
Average Sales Price
Gas (per Mcf)		$7.75		$5.70		$6.59
Oil (per Bbl)		$104.62		$64.35		$63.73

Oil and Natural Gas Reserves

General

Miller and Lents, Ltd., independent petroleum engineers, has estimated oil and gas reserves attributable to the underlying properties as of December 31, 2008, 2007, 2006 and 2005. The estimated reserves for the underlying properties are then used by XTO Energy to calculate the estimated oil and gas reserves attributable to the net profits interests. Numerous uncertainties are inherent in estimating reserve volumes and values, and such estimates are subject to change as additional information becomes available. The reserves actually recovered and the timing of production of these reserves may be substantially different from the original estimates.

Reserve quantities and revenues for the net profits interests were estimated from projections of reserves and revenues attributable to 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 a specific percentage of the oil and gas reserve quantities. Accordingly, reserves allocated to the trust pertaining to its 80% net profits interests in the properties have effectively been reduced to reflect recovery of the trust’s 80% portion of applicable production and development costs. Because trust reserve quantities are determined using an allocation formula, any fluctuations in actual or assumed prices or costs will result in revisions to the estimated reserve quantities allocated to the net profits interests.

The standardized measure of discounted future net cash flows and changes in such discounted cash flows as presented below are prepared using assumptions required by the Financial Accounting Standards Board. These assumptions include the use of year-end prices for oil and gas and year-end costs for estimated future development and production expenditures to produce the proved reserves. Because natural gas prices are influenced by seasonal demand, use of year-end prices, as required by the Financial Accounting Standards Board, may not be the most representative in estimating future revenues or reserve data. Future net cash flows are discounted at an annual rate of 10%. No provision is included for federal income taxes since future net cash flows are not subject to taxation at the trust level.

Estimated costs to plug and abandon wells on the underlying properties at the end of their productive lives have not been deducted 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 the underlying working interests and will only be

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deducted from net proceeds payable to the trust if net proceeds from the related conveyance exceed such costs when paid, subject to excess cost carryforward provisions as described under Item 1.

Year-end weighted average realized gas prices used to determine the standardized measure were $4.47 per Mcf in 2008, $6.72 per Mcf in 2007, $5.60 per Mcf in 2006 and $8.72 per Mcf in 2005. Year-end oil prices used to determine the standardized measure were based on a West Texas Intermediate crude oil posted price of $41.22 per Bbl in 2008, $92.70 per Bbl in 2007, $57.75 per Bbl in 2006 and $57.75 per Bbl in 2005.

Proved Reserves

	Underlying Properties						Net Profits Interests
	Gas (Mcf)			Oil (Bbls)			Gas (Mcf)			Oil (Bbls)
(in Thousands)
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
Extensions, additions and discoveries		13,647			167			7,270			89
Revisions of prior estimates		(534	)		(54	)		(1,764	)		(33	)
Production – sales volumes		(28,092	)		(306	)		(11,234	)		(141	)
Balance, December 31, 2007		405,473			3,645			224,948			2,110
Extensions, additions and discoveries		10,493			120			3,432			39
Revisions of prior estimates		(21,485	)		(114	)		(36,762	)		(297	)
Production – sales volumes		(28,176	)		(342	)		(13,135	)		(170	)
Balance, December 31, 2008		366,305			3,309			178,483			1,682

Extensions, additions and discoveries in 2006, 2007 and 2008 are primarily related to delineation of additional proved undeveloped reserves in the Anadarko and Green River Basins. Revisions of prior estimates of the proved gas reserves for the underlying properties in each year are primarily because of changes in the year-end gas and oil prices. Higher upward and downward revisions for the net profits interests as compared with the underlying properties in each year were caused by changes in year-end oil and gas prices and estimated future production and development costs which resulted in an increase or decrease in gas reserves allocated to the trust.

Proved Developed Reserves

	Underlying Properties				Net Profits Interests
	Gas (Mcf)		Oil (Bbls)		Gas (Mcf)		Oil (Bbls)
(in Thousands)
December 31, 2005		379,527		3,361		235,470		2,180
December 31, 2006		361,915		3,369		202,794		1,964
December 31, 2007		352,732		3,234		198,187		1,896
December 31, 2008		325,891		2,960		164,080		1,554

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Standardized Measure of Discounted Future Net Cash Flows from Proved Reserves

	December 31
	2008		2007		2006
(in Thousands)
Underlying Properties
Future cash inflows	$	1,786,971	$	3,061,372	$	2,574,507
Future costs:
Production		711,349		1,014,076		858,794
Development		66,456		78,494		86,744
Future net cash flows		1,009,166		1,968,802		1,628,969
10% discount factor		494,416		992,874		830,281
Standardized measure	$	514,750	$	975,928	$	798,688
Net Profits Interests
Future cash inflows	$	875,222	$	1,714,576	$	1,420,936
Future production taxes		67,889		139,535		117,760
Future net cash flows		807,333		1,575,041		1,303,176
10% discount factor		395,533		794,299		664,225
Standardized measure	$	411,800	$	780,742	$	638,951

Changes in Standardized Measure of Discounted Future Net Cash Flows from Proved Reserves

	2008			2007			2006
(in Thousands)
Underlying Properties
Standardized measure, January 1	$	975,928		$	798,688		$	1,390,431
Revisions:
Prices and costs		(365,784	)		208,352			(578,041	)
Quantity estimates		(9,546	)		(18,232	)		5,912
Accretion of discount		84,305			69,710			119,526
Future development costs		(28,435	)		(28,733	)		(53,060	)
Production rates and other		(542	)		(1,708	)		(944	)
Net revisions		(320,002	)		229,389			(506,607	)
Extensions, additions and discoveries		5,409			35,122			28,915
Production		(192,585	)		(130,021	)		(165,751	)
Development costs		46,000			42,750			51,700
Net change		(461,178	)		177,240			(591,743	)
Standardized measure, December 31	$	514,750		$	975,928		$	798,688
Net Profits Interests
Standardized measure, January 1	$	780,742		$	638,951		$	1,112,345
Extensions, additions and discoveries		4,327			28,097			23,132
Accretion of discount		67,444			55,768			95,621
Revisions of prior estimates, changes in price and other		(323,445	)		128,426			(500,906	)
Net profits income		(117,268	)		(70,500	)		(91,241	)
Standardized measure, December 31	$	411,800		$	780,742		$	638,951

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Regulation

Natural Gas Regulation

The interstate transportation and sale for resale of natural gas is subject to federal regulation, including transportation rates charged, storage tariffs and various other matters, by the Federal Energy Regulatory Commission. Federal price controls on wellhead sales of domestic natural gas terminated on January 1, 1993. On August 8, 2005, Congress enacted the Energy Policy Act of 2005. The Energy Policy Act, among other things, amended the Natural Gas Act to prohibit market manipulation by any entity, to direct FERC to facilitate market transparency in the market for sale or transportation of physical natural gas in interstate commerce, and to significantly increase the penalties for violations of the Natural Gas Act, the Natural Gas Policy Act of 1978, or FERC rules, regulations or orders thereunder. FERC has promulgated new regulations to implement the Energy Policy Act. While natural gas prices are currently unregulated, Congress historically has been active in the area of natural gas regulation. It is impossible to predict whether new legislation to regulate natural gas might be proposed, what proposals, if any, might actually be enacted, and what effect, if any, such proposals might have on the operations of the underlying properties.

On December 19, 2007, the President signed into law the Energy Independence & Security Act of 2007 (PL 110-140). The EISA, among other things, prohibits market manipulation by any person in connection with the purchase or sale of crude oil, gasoline or petroleum distillates at wholesale in contravention of such rules and regulations that the Federal Trade Commission may prescribe, directs the Federal Trade Commission to enforce the regulations, and establishes penalties for violations thereunder. XTO Energy has advised the trustee that it cannot predict the impact of future government regulation on any natural gas facilities.

Environmental Regulation

Companies that are engaged in the oil and gas industry are affected by federal, state and local laws regulating the discharge of materials into the environment. Those laws may impact operations of the underlying properties. No material expenses have been incurred on the underlying properties in complying with environmental laws and regulations. XTO Energy does not expect that future compliance will have a material adverse effect on the trust.

State Regulation

The various states regulate the production and sale of oil and natural gas, including imposing requirements for obtaining drilling permits, the method of developing new fields, the spacing and operation of wells and the prevention of waste of oil and gas resources. The rates of production may be regulated and the maximum daily production allowables from both oil and gas wells may be established on a market demand or conservation basis, or both.

State Tax Withholding

Several states have enacted legislation to require state income tax withholding from nonresident recipients of oil and gas proceeds. After consultation with its state tax counsel, XTO Energy has advised the trustee that it believes the trust is not subject to these withholding requirements. However, regulations are subject to change by the various states, which could change this conclusion. Should the trust be required to withhold state taxes, distributions to the unitholders would be reduced by the required amount, subject to the unitholder’s right to file a state tax return to claim any refund due.

Other Regulation

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

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The petroleum industry is also subject to compliance with various other federal, state and local regulations and laws, including, but not limited to, regulations and laws relating to environmental protection, occupational safety, resource conservation and equal employment opportunity. XTO Energy has advised the trustee that it does not believe that compliance with these laws will have any material adverse effect upon the unitholders.

Pricing and Sales Information

A subsidiary of XTO Energy purchases most of XTO Energy’s natural gas production based on a monthly published index price or at a weighted average of several monthly published index prices, then sells the gas to third parties for the best available price. The monthly published index price is the price established during the last five business days of the month preceding the month of delivery for the specific delivery location, which is based on the average of all fixed price transactions that occur at a specific delivery location. The fixed price is determined by the NYMEX price less the location differential during this period. Any marketing gains or losses are not included in trust net proceeds. Oil production is generally marketed at the wellhead to third parties at the best available price. XTO Energy arranges for some of its natural gas to be processed by unaffiliated third parties and markets the natural gas liquids. The natural gas attributable to the underlying properties is marketed under contracts existing at trust inception. Contracts covering production from the Ringwood area of the Major County area are generally for the life of the lease, and the contract for the majority of production from the Hugoton area was extended through 2009. If new contracts are entered with unaffiliated third parties, the proceeds from sales under those new contracts will be included in gross proceeds from the underlying properties. If new contracts are entered with XTO Energy’s marketing subsidiary, it may charge XTO Energy a fee that may not exceed 2% of the sales price of the oil and natural gas received from unaffiliated parties. The sales price is net of any deductions for transportation from the wellhead to the unaffiliated parties and any gravity or quality adjustments.

Item 3. Legal Proceedings

On October 17, 1997, an action, styled United States of America ex rel. Grynberg v. Cross Timbers Oil Company, et al., was filed in the United States District Court for the Western District of Oklahoma by Jack J. Grynberg on behalf of the United States under the qui tam provisions of the U.S. False Claims Act against XTO Energy. The plaintiff alleges that XTO Energy underpaid royalties on natural gas produced from federal leases and lands owned by Native Americans in amounts in excess of 20% as a result of mismeasuring the volume of natural gas, incorrectly analyzing its heating content and improperly valuing the natural gas during at least the past ten years. The plaintiff seeks treble damages for the unpaid royalties (with interest, attorney’s fees and expenses), civil penalties between $5,000 and $10,000 for each violation of the U.S. False Claims Act, and an order for XTO Energy to cease the allegedly improper measuring practices. This lawsuit against XTO Energy and similar lawsuits filed by Grynberg against more than 300 other companies was consolidated in the United States District Court for Wyoming. In October 2002, the court granted a motion to dismiss Grynberg’s royalty valuation claims, and Grynberg’s appeal of this decision was dismissed for lack of appellate jurisdiction in May 2003. In response to a motion to dismiss filed by XTO Energy and other defendants, in October 2006 the district judge held that Grynberg failed to establish the jurisdictional requirements to maintain the action against XTO Energy and other defendants and dismissed the actions for lack of subject matter jurisdiction. Grynberg has filed an appeal of this decision. While XTO Energy is unable to predict the final outcome of this case or estimate the amount of any possible loss, it has informed the trustee that it believes that the allegations of this lawsuit are without merit and intends to vigorously defend the action. However, an order to change measuring practices or a related settlement could adversely affect the trust by reducing net proceeds in the future by an amount that is presently not determinable, but, in XTO Energy management’s opinion, is not currently expected to be material to the trust’s annual distributable income, financial position or liquidity.

An amended petition for a class action lawsuit, Beer, et al. v. XTO Energy Inc., was filed in January 2006, in the District Court of Texas County, Oklahoma by royalty owners of natural gas wells in Oklahoma. The plaintiffs allege that XTO Energy has not properly accounted to the plaintiffs for the royalties to which they are entitled and seek an accounting regarding the natural gas and other products produced from their wells and the prices paid for the natural gas and other products produced, and for payment of the monies

14

allegedly owed since June 2002, with a certain limited number of plaintiffs claiming monies owed for additional time. XTO Energy removed the case to federal district court in Oklahoma City. A hearing on the class certification was conducted in October 2008. No decision has been made. The plaintiffs have not alleged in their petition an amount that they are seeking. XTO Energy has informed the trustee that it believes that it has strong defenses to this lawsuit and intends to vigorously defend its position. However, if XTO Energy ultimately makes any settlement payments or receives a judgment against it, the trust will bear its 80% share of such settlement or judgment related to production from the underlying properties. Additionally, if a judgment or settlement increases the amount of future payments to royalty owners, the trust would bear its proportionate share of the increased payments through reduced net proceeds. XTO Energy has informed the trustee that, although the amount of any reduction in net proceeds is not presently determinable, in its management’s opinion, the amount is not currently expected to be material to the trust’s annual distributable income, financial position or liquidity.

In September 2008, a class action lawsuit was filed against XTO Energy styled Wallace B. Roderick Revocable Living Trust, et al. v. XTO Energy Inc. in the District Court of Kearny County, Kansas. XTO Energy removed the case to federal court in Wichita, Kansas. The plaintiffs allege that XTO Energy has improperly taken post-production costs from royalties paid to the plaintiffs from wells located in Kansas, Oklahoma and Colorado. The plaintiffs also seek to represent all royalty owners in these three states as a class. The plaintiff’s claims overlap the claims made by the plaintiffs in the Beer case as to certain properties. XTO Energy has answered and denied all claims. XTO Energy has informed the trustee that it believes that XTO Energy has strong defenses to this lawsuit and intends to vigorously defend its position. However, if XTO Energy ultimately makes any settlement payments or receives a judgment against it, the trust will bear its 80% share of such settlement or judgment related to production from the underlying properties. Additionally, if the judgment or settlement increases the amount of future payments to royalty owners, the trust would bear its proportionate share of the increased payments through reduced net proceeds. XTO Energy has informed the trustee that, although the amount of any reduction in net proceeds is not presently determinable, in its management’s opinion, the amount is not currently expected to be material to the trust’s annual distributable income, financial position or liquidity.

Certain of the underlying properties are involved in various other lawsuits and certain governmental proceedings arising in the ordinary course of business. XTO Energy has advised the trustee that it does not believe that the ultimate resolution of these claims will have a material effect on trust annual distributable income, financial position or liquidity.

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

No matters were submitted to a vote of unitholders during 2008.

15

PART II

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

The section entitled “Units of Beneficial Interest” in the trust’s annual report to unitholders for the year ended December 31, 2008 is incorporated herein by reference.

The trust has no equity compensation plans, nor has it purchased any units during the period covered by this report.

Item 6. Selected Financial Data

	Year Ended December 31
	2008		2007		2006		2005		2004
Net Profits Income	$	117,268,069	$	70,499,584	$	91,241,196	$	105,129,321	$	81,920,014
Distributable Income		116,494,400		69,388,520		90,910,760		104,831,880		81,596,920
Distributable Income per Unit		2.912360		1.734713		2.272769		2.620797		2.039923
Distributions per Unit		2.912360		1.734713		2.272769		2.620797		2.039923
Total Assets at Year-End		147,867,855		161,034,033		165,609,772		185,459,610		189,499,334

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

The “Trustee’s Discussion and Analysis” of financial condition and results of operations for each of the years in the three-year period ended December 31, 2008 in the trust’s annual report to unitholders for the year ended December 31, 2008 is incorporated herein by reference.

Liquidity and Capital Resources

The trust’s only cash requirement is the monthly distribution of its income to unitholders, which is funded by the monthly receipt of net profits income after payment of trust administration expenses. The trust is not liable for any production costs or liabilities attributable to the net profits interests. If at any time the trust receives net profits income in excess of the amount due, the trust is not obligated to return such overpayment, but future net profits income payable to the trust will be reduced by the overpayment, plus interest at the prime rate. The trust may borrow funds required to pay trust liabilities if fully repaid prior to further distributions to unitholders.

The trust does not have any transactions, arrangements or other relationships with unconsolidated entities or persons that could materially affect the trust’s liquidity or the availability of capital resources.

Off-Balance Sheet Arrangements

The trust has no off-balance sheet financing arrangements. The trust has not guaranteed the debt of any other party, nor does the trust have any other arrangements or relationships with other entities that could potentially result in unconsolidated debt, losses or contingent obligations.

Contractual Obligations

As shown below, the trust had no obligations and commitments to make future contractual payments as of December 31, 2008, other than the December distribution payable to unitholders in January 2009, as reflected in the statement of assets, liabilities and trust corpus.

	Payments due by Period
	Total		Less than 1 Year		1 – 3 Years		3 – 5 Years		More than 5 Years
Distribution payable to unitholders	$	1,145,840	$	1,145,840	$	—	$	—	$	—

Related Party Transactions

The underlying properties from which the net profits interests were carved are currently owned by XTO Energy, which operates approximately 94% of the underlying properties. In computing net proceeds, XTO Energy deducts a monthly overhead charge for reimbursement of administrative expenses on the underlying properties it operates. As of December 31, 2008, the monthly overhead charge, based on the number of operated wells, was approximately $850,000 ($680,000 net to the trust) and is subject to annual adjustment based on an oil and gas industry index.

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In May 2006, XTO Energy distributed all of its remaining 21.7 million trust units as a dividend to its common stockholders. XTO Energy currently is not a unitholder of the trust.

XTO Energy sells a significant portion of natural gas production from the underlying properties to certain of XTO Energy’s wholly owned subsidiaries under contracts in existence when the trust was created, generally at amounts approximating monthly published market prices. For further information regarding natural gas sales from the underlying properties to affiliates of XTO Energy, see Item 2, Properties, and Note 7 to Financial Statements in the trust’s annual report to unitholders for the year ended December 31, 2008. Total gas sales from the underlying properties to XTO Energy’s wholly owned subsidiaries were $103.3 million for 2008, or 47% of total gas sales, $76.6 million for 2007, or 48% of total gas sales and $103.2 million for 2006, or 53% of total gas sales.

Critical Accounting Policies

The financial statements of the trust are significantly affected by its basis of accounting and estimates related to its oil and gas properties and proved reserves, as summarized below.

Basis of Accounting

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

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

• Expenses are recognized when paid rather than when incurred.

• Cash reserves may be established by the trustee for certain contingencies that would not be recorded under U.S. generally accepted accounting principles.

This comprehensive basis of accounting other than U.S. generally accepted accounting principles corresponds to the accounting permitted for royalty trusts by the U.S. Securities and Exchange Commission, as specified by Staff Accounting Bulletin Topic 12:E, Financial Statements of Royalty Trusts. For further information regarding the trust’s basis of accounting, see Note 2 to Financial Statements in the trust’s annual report to unitholders for the year ended December 31, 2008.

All amounts included in the trust’s financial statements are based on cash amounts received or disbursed, or on the carrying value of the net profits interests, which was derived from the historical cost of the interests at the date of their transfer from XTO Energy, less accumulated amortization to date. Accordingly, there are no fair value estimates included in the financial statements based on either exchange or nonexchange trade values.

Oil and Gas Reserves

The proved oil and gas reserves for the underlying properties are estimated by independent petroleum engineers. The estimated reserves for the underlying properties are then used by XTO Energy to calculate the estimated oil and gas reserves attributable to the net profits interests. Reserve engineering is a subjective process that is dependent upon the quality of available data and the interpretation thereof. Estimates by different engineers often vary, sometimes significantly. In addition, physical factors such as the results of drilling, testing and production subsequent to the date of an estimate, as well as economic factors such as changes in product prices, may justify revision of such estimates. Because proved reserves are required to be estimated using prices at the date of the evaluation, estimated reserve quantities can be significantly impacted by changes in product prices. Accordingly, oil and gas quantities ultimately recovered and the timing of production may be substantially different from original estimates.

The standardized measure of discounted future net cash flows and changes in such cash flows, as reported in Item 2, is prepared using assumptions required by the Financial Accounting Standards Board and the Securities and Exchange Commission. Such assumptions include using year-end oil and gas prices and

17

year-end costs for estimated future development and production expenditures. Discounted future net cash flows are calculated using a 10% rate. Changes in any of these assumptions, including consideration of other factors, could have a significant impact on the standardized measure. Accordingly, the standardized measure does not represent XTO Energy’s or the trustee’s estimated current market value of proved reserves.

Pending Securities and Exchange Commission Rule

In December 2008, the Securities and Exchange Commission (SEC) released Final Rule, Modernization of Oil and Gas Reporting. The new disclosure requirements include provisions that permit the use of new technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserves volumes. The new requirements also will allow companies to disclose their probable and possible reserves to investors. In addition, the new disclosure requirements require companies to: (a) report the independence and qualifications of its reserves preparer or auditor; (b) file reports when a third party is relied upon to prepare reserves estimates or conducts a reserves audit; and (c) report oil and gas reserves using an average price based upon the prior 12-month period rather than year-end prices. The new disclosure requirements are effective for financial statements for fiscal years ending on or after December 31, 2009. The effect of adopting the SEC rule has not been determined, but it is not expected to have a significant effect on our reported financial position or distributable income.

Forward-Looking Statements

Certain information included in this annual report and other materials filed, or to be filed, by the trust with the Securities and Exchange Commission (as well as information included in oral statements or other written statements made or to be made by XTO Energy or the trustee) contain forward-looking statements within the meaning 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 the trust, operations of the underlying properties and the oil and gas industry. Such forward-looking statements may concern, among other things, reserve-to-production ratios, future production, development activities, future development plans by area, increased density drilling, maintenance projects, development, production and other costs, oil and gas prices, pricing differentials, proved reserves, future net cash flows, production levels, litigation, regulatory matters and competition. Such forward-looking statements are based on XTO Energy’s current plans, expectations, assumptions, projections and estimates and are identified by words such as “expects,” “intends,” “plans,” “projects,” “anticipates,” “predicts,” “believes,” “goals,” “estimates,” “should,” “could,” and similar words that convey the uncertainty of future events. These statements are not guarantees of future performance and involve certain risks, uncertainties and assumptions that are difficult to predict. Therefore, actual results may differ materially from expectations, estimates or assumptions expressed in, implied in, or forecasted in such forward-looking statements. Some of the risk factors that 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 and sources of income to the trust are the net profits interests, which generally entitle the trust to receive a share of the net profits from oil and gas production from the underlying properties. Consequently, the trust is exposed to market risk from fluctuations in oil and gas prices. The trust is a passive entity and, other than the trust’s ability to periodically borrow money as necessary to pay expenses, liabilities and obligations of the trust that cannot be paid out of cash held by the trust, the trust is prohibited from engaging in borrowing transactions. The amount of any such borrowings is unlikely to be material to the trust. In addition, the trustee is prohibited by the trust indenture from engaging in any business activity or causing the trust to enter into any investments other than investing cash on hand in specific short-term cash investments. Therefore, the trust cannot hold any derivative financial instruments. As a result of the limited nature of its borrowing and investing activities, the trust is not subject to any material interest rate market risk. Additionally, any gains or losses from any hedging activities conducted by XTO Energy are specifically excluded from the calculation of net proceeds due the trust under the forms of the conveyances. The trust does not engage in transactions in foreign currencies which could expose the trust to any foreign currency related market risk.

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Item 8. Financial Statements and Supplementary Data

The financial statements of the trust and the notes thereto, together with the related reports of KPMG LLP dated February 25, 2009, appearing in the trust’s annual report to unitholders for the year ended December 31, 2008, are incorporated herein by reference.

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

There have been no changes in accountants and no disagreements with the trust’s independent registered public accountants on any matter of accounting principles or practices or financial statement disclosures during the two years ended December 31, 2008.

Item 9A. Controls and Procedures

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

The trustee conducted an evaluation of the trust’s disclosure controls and procedures, as such term is defined under Rule 13a-15(e) promulgated under the Securities Exchange Act of 1934, as amended. Based on this evaluation, the trustee has concluded that the trust’s disclosure controls and procedures were effective as of the end of the period covered by this annual report. In its evaluation of disclosure controls and procedures, the trustee has relied, to the extent considered reasonable, on information provided by XTO Energy.

Trustee’s Report on Internal Control Over Financial Reporting

The trustee, Bank of America, N.A., also known as U.S. Trust, Bank of America Private Wealth Management, is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Rule 13a-15(f) promulgated under the Securities Exchange Act of 1934, as amended. The trustee conducted an evaluation of the effectiveness of the trust’s internal control over financial reporting based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on the trustee’s evaluation under the framework in Internal Control—Integrated Framework, the trustee concluded that the trust’s internal control over financial reporting was effective as of December 31, 2008. The effectiveness of the trust’s internal control over financial reporting as of December 31, 2008 has been audited by KPMG LLP, an independent registered public accounting firm, as stated in their report in the trust’s annual report to unitholders for the year ended December 31, 2008 which is incorporated herein by reference.

There were no changes in the trust’s internal control over financial reporting during the quarter ended December 31, 2008 that have materially affected, or are reasonably likely to materially affect, the trust’s internal control over financial reporting.

Item 9B. Other Information

None.

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PART III

Item 10. Directors, Executive Officers and Corporate Governance

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

Section 16(a) of the Securities Exchange Act of 1934 requires that beneficial owners of more than 10% of the registrant’s equity securities file initial reports of beneficial ownership and reports of changes in beneficial ownership with the Securities and Exchange Commission and the New York Stock Exchange. The Securities and Exchange Commission has taken the position that executive officers and directors of XTO Energy must also file initial ownership reports and reports of changes in beneficial ownership. Copies of the reports must be provided to the trustee. To the trustee’s knowledge, based solely on the information furnished to the trustee, the trustee is unaware of any person that failed to file on a timely basis reports required by Section 16(a) filing requirements with respect to the trust units of beneficial interest during and for the year ended December 31, 2008, other than one late filing of one transaction on Form 4 by Scott G. Sherman a director of XTO Energy and one late filing of initial holdings on Form 3 by Gary Simpson, an advisory director of XTO Energy. The transaction and holdings have now been reported.

Because the trust has no employees, it does not have a code of ethics. Employees of the trustee, U.S. Trust, Bank of America Private Wealth Management, must comply with the bank’s code of ethics, a copy of which will be provided to unitholders, without charge, upon request by appointment at Bank of America Plaza, 17^th Floor, 901 Main Street, Dallas, Texas 75202.

Item 11. Executive Compensation

The trustee received the following annual compensation from 2006 through 2008 as specified in the trust indenture:

Name and Principal Position	Year		Other Annual Compensation(1)
U.S. Trust, Bank of America Private Wealth Management, Trustee		2008	$	45,602
		2007		43,022
		2006		47,410

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

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters

The trust has no equity compensation plans.

(a) Security Ownership of Certain Beneficial Owners.  The trustee is not aware of any person who beneficially owns more than 5% of the outstanding units.

(b) Security Ownership of Management.  The trust has no directors or executive officers. As of February 10, 2009, Bank of America, N.A. owned, in various fiduciary capacities, 174,438 units, with a shared right to vote 82,953 of these units and no right to vote 91,485 of these units. Bank of America, N.A. disclaims any beneficial interests in these units. The number of units reflected in this paragraph includes units held by all branches of Bank of America, N.A.

(c) Changes in Control.  The trustee knows of no arrangements which may subsequently result in a change in control of the trust.

Item 13. Certain Relationships and Related Transactions, and Director Independence

In computing net profits income paid to the trust for the net profits interests, XTO Energy deducts an overhead charge for reimbursement of administrative expenses of operating the underlying properties. This charge at December 31, 2008 was approximately $850,000 per month, or $10,200,000 annually (net to the

20

trust of $680,000 per month or $8,160,000 annually, and is subject to annual adjustment based on an oil and gas industry index as defined in the trust agreement.

XTO Energy sells a significant portion of natural gas production from the underlying properties to certain of its wholly owned subsidiaries under contracts in existence when the trust was created, generally at amounts approximating monthly published prices. For further information, see “Hugoton Area,” “Anadarko Basin,” “Green River Basin” and “Pricing and Sales Information,” of Item 2.

See Item 11 for the remuneration received by the trustee from 2006 through 2008 and Item 12(b) for information concerning units owned by the trustee in various fiduciary capacities.

As noted in Item 10, the trust has no directors, executive officers or audit committee. The trustee is a corporate trustee which may be removed, with or without cause, by the affirmative vote of the holders of a majority of all the units then outstanding.

Item 14. Principal Accountant Fees and Services

Fees for services performed by KPMG LLP for the years ended December 31, 2008 and 2007:

	2008		2007
Audit fees	$	74,938	$	71,750
Audit-related fees		—		—
Tax fees		—		—
All other fees		—		—
	$	74,938	$	71,750

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

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PART IV

Item 15. Exhibits and Financial Statement Schedules

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

1. Financial Statements (incorporated by reference in Item 8 of this report)

Independent Registered Public Accounting Firm Reports
Statements of Assets, Liabilities and Trust Corpus at December 31, 2008 and 2007
Statements of Distributable Income for the years ended December 31, 2008, 2007 and 2006
Statements of Changes in Trust Corpus for the years ended December 31, 2008, 2007 and 2006
Notes to Financial Statements

2. Financial Statement Schedules

Financial statement schedules are omitted because of the absence of conditions under which they are required or because the required information is given in the financial 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.

    (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, 2008

(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 any unitholder, at the actual cost of reproduction, upon written request to the trustee, U.S. Trust, Bank of America Private Wealth Management, P.O. Box 830650, Dallas, Texas 75283-0650.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this Report to be signed on its behalf 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: February 25, 2009

By /s/ Louis G. Baldwin

Louis G. Baldwin
Executive Vice President and
Chief Financial Officer

(The trust has no directors or executive officers.)

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EX-13

EXHIBIT 13

HUGOTON ROYALTY TRUST

GLOSSARY OF TERMS

The following are definitions of significant terms used in this Annual Report:

Bbl

Barrel (of oil)

Bcf

Billion cubic feet (of natural gas)

Mcf

Thousand cubic feet (of natural gas)

MMBtu

One million British Thermal Units, a common energy measurement

net proceeds

Gross proceeds received by XTO Energy from sale of production from the underlying properties, less applicable costs, as defined in the net profits interest conveyances.

net profits income

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

net profits interest

An interest in an oil and gas property measured by net profits from the sale of production, rather than a specific portion of production. The following defined net profits interests were conveyed to the trust from the underlying properties:

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

underlying properties

XTO Energy’s interest in certain oil and gas properties from which the net profits interests were conveyed. The underlying properties include working interests in predominantly gas-producing properties located in Kansas, Oklahoma and Wyoming.

working interest

An operating interest in an oil and gas property that provides the owner a specified share of production that is subject to all production expense and development costs.

THE TRUST

Hugoton Royalty Trust was created on December 1, 1998 when XTO Energy Inc. conveyed 80% net profits interests in certain predominantly gas-producing properties located in Kansas, Oklahoma and Wyoming to the trust. The net profits interests are the only assets of the trust, other than cash held for trust expenses and for distribution to unitholders.

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

UNITS OF BENEFICIAL INTEREST

The units of beneficial interest in the trust began trading on the New York Stock Exchange on April 9, 1999 under the symbol “HGT.” The following are the high and low unit sales prices and total cash distributions per unit paid by the trust during each quarter of 2008 and 2007:

	Sales Price				Distributions per Unit
Quarter	High		Low
2008
First		$29.85		$22.52		$0.544229
Second		37.86		27.14		0.838873
Third		37.65		24.50		1.092216
Fourth		27.29		14.00		0.437042
						$2.912360

2007
First		$25.50		$22.61		$0.406057
Second		28.25		24.31		0.521150
Third		26.83		22.25		0.443367
Fourth		25.40		21.93		0.364139
						$1.734713

At December 31, 2008, there were 40,000,000 units outstanding and approximately 1,091 unitholders of record; 39,134,314 of these units were held by depository institutions.

1

Forward-Looking Statements

This Annual Report, including the accompanying Form 10-K, includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements other than statements of historical fact included in this Annual Report and Form 10-K, including, without limitation, statements regarding estimates of proved reserves, future development plans and costs, and industry and market conditions, are forward-looking statements that are subject to a number of risks and uncertainties which are detailed in Part I, Item 1A of the accompanying Form 10-K. Although XTO Energy and the trustee believe that the expectations reflected in such forward-looking statements are reasonable, neither XTO Energy nor the trustee can give any assurance that such expectations will prove to be correct.

2

SUMMARY

The trust was created to collect and distribute to unitholders monthly net profits income related to the 80% net profits interests. Such net profits income is calculated as 80% of the net proceeds received from certain working interests in predominantly gas-producing properties in Kansas, Oklahoma and Wyoming. Net proceeds from properties in each state are calculated by deducting production expense, development costs and overhead from revenues. If monthly costs exceed revenues from the underlying properties in any state, such excess costs must be recovered, with accrued interest, from future net proceeds of that state and cannot reduce net profits income from another state. Excess costs generally can occur during periods of higher development activity and/or lower gas prices.

Costs exceeded revenues on properties underlying the Wyoming net profits interests in November 2008 and November and December 2007. For further information on excess costs, see “Trustee’s Discussion and Analysis.”

• Cost Depletion is generally available to unitholders as a deduction from royalty income. Available depletion is dependent upon the unitholder’s cost of units, purchase date and prior allowable depletion. It may be more beneficial for unitholders to deduct percentage depletion. Unitholders should consult their tax advisors for further information.

As an example, a unitholder that acquired units in January 2008 and held them throughout 2008 would be entitled to a cost depletion deduction of approximately 6% of his cost. Assuming a cost of $25.00 per unit, cost depletion would offset approximately 51% of 2008 taxable trust income. Assuming a 30% tax rate, the 2008 taxable equivalent return as a percentage of unit cost would be 14%. (NOTE — Because the units are a depleting asset, a portion of this return is effectively a return of capital.)

3

TO UNITHOLDERS

We are pleased to present the 2008 Annual Report of the Hugoton Royalty Trust. This report includes a copy of the trust’s 2008 Form 10-K as filed with the Securities and Exchange Commission. Both reports contain important information about the trust’s net profits interests, including information provided to the trustee by XTO Energy, and should be read in conjunction with each other.

For the year ended December 31, 2008, net profits income totaled $117,268,069. After adding interest income of $91,203 and deducting trust administration expense of $864,872, distributable income was $116,494,400 or $2.912360 per unit. Net profits income and distributions were 66% and 68%, respectively, higher than 2007 amounts primarily because of higher oil and gas prices and increased oil production, partially offset by increased production expense, higher taxes, transportation and other costs and higher development costs.

Natural gas prices averaged $7.75 per Mcf for 2008, 36% higher than the 2007 average price of $5.70 per Mcf. The average 2008 oil price was $104.62 per Bbl, 63% higher than the 2007 average price of $64.35 per Bbl.

Gas sales volumes from the underlying properties for 2008 were 28,176,094 Mcf, or 76,984 Mcf per day, relatively flat compared to 76,965 Mcf per day in 2007. Oil sales volumes from the underlying properties were 341,754 Bbls, or 934 Bbls per day in 2008, an increase of 12% from 837 Bbls per day in 2007. For further information on sales volumes and product prices, see “Trustee’s Discussion and Analysis.”

As of December 31, 2008, proved reserves for the underlying properties were estimated by independent engineers to be 366.3 Bcf of natural gas and 3.3 million Bbls of oil. Natural gas reserves for the underlying properties declined 39.2 Bcf and oil reserves for the underlying properties declined approximately 336,000 Bbls primarily due to current year production and revisions due to lower year-end gas and oil prices, partially offset by additions from development activity. Based on an allocation of these reserves, proved reserves attributable to the net profits interests were estimated to be 178.5 Bcf of natural gas and 1.7 million Bbls of oil. Estimated gas and oil reserves attributable to the net profits interests declined from previously reported reserves at year-end 2007, as current year production and revisions due to lower year-end prices were only partially offset by additions from development activities. All reserve information prepared by independent engineers has been provided to the trustee by XTO Energy.

Estimated future net cash flows from proved reserves of the net profits interests at December 31, 2008 are $807 million. Using an annual discount factor of 10%, the present value of estimated future net cash flows at December 31, 2008 is $412 million. Proved reserve estimates and related future net cash flows have been determined based on a year-end average realized gas price of $4.47 per Mcf and a year-end West Texas Intermediate posted oil price of $41.22 per Bbl. Other guidelines used in estimating proved reserves, as prescribed by the Financial Accounting Standards Board, are described under Item 2 of the accompanying Form 10-K. The present value of estimated future net cash flows is computed based on SEC guidelines and is not necessarily representative of the market value of trust units.

As disclosed in the tax instructions provided to unitholders in February 2009, trust distributions are considered portfolio income, rather than passive income. Unitholders should consult their tax advisors for further information.

Hugoton Royalty Trust
By:  U.S. Trust, Bank of America
Private Wealth Management, Trustee

By:  Nancy G. Willis
Vice President

4

THE UNDERLYING PROPERTIES

The underlying properties are predominantly gas-producing properties with established production histories in the Hugoton area of Oklahoma and Kansas, the Anadarko Basin of Oklahoma and the Green River Basin of Wyoming. The average reserve-to-production index for the underlying properties as of December 31, 2008 is approximately 13 years. This index is calculated using total proved reserves and estimated 2009 production for the underlying properties. The projected 2009 production is from proved developed producing reserves as of December 31, 2008. Based on estimated future net cash flows at year-end oil and gas prices, the proved reserves of the underlying properties are approximately 92% natural gas and 8% oil. XTO Energy operates approximately 94% of the underlying properties.

Because the underlying properties are working interests, production expense, development costs and overhead are deducted in calculating net profits income. As a result, net profits income is affected by the level of maintenance and development activity on the underlying properties. See “Trustee’s Discussion and Analysis  — Years Ended December 31, 2008, 2007 and 2006 — Costs.” Total 2008 development costs deducted for the underlying properties were $46 million, an increase of 8% from the prior year. XTO Energy has informed the trustee that total 2009 budgeted development costs for the underlying properties are approximately $33 million.

Hugoton Area

Discovered in 1922, the Hugoton area is one of the largest natural gas producing areas in the United States. During 2008, gas sales volumes from the underlying properties in the Hugoton area were 7.6 Bcf, or approximately 27% of total sales volumes from the underlying properties. Most of the production is from the Chase formation. XTO Energy has informed the trustee that it plans to develop other formations, including the Council Grove, Chester, Morrow and St. Louis formations that underlie the 79,500 net acres held by production by the Chase formation wells.

Within this area, XTO Energy performed 13 workovers in 2008, of which 2 were Chase restimulations. XTO Energy has informed the trustee that it does not plan to drill any new wells and will perform up to 16 workovers in this area during 2009.

Anadarko Basin

The Anadarko Basin of western Oklahoma was discovered in 1945. Gas sales volumes from the underlying properties in the Anadarko Basin totaled 13.0 Bcf in 2008, or approximately 46% of total sales volumes from the underlying properties. XTO Energy is one of the largest producers in the Ringwood, Northwest Okeene and Cheyenne Valley fields of Major County, the Northeast Cedardale field of Woodward County and the Elk City field of Beckham County, the principal producing regions of the underlying properties in the Anadarko Basin.

In Major County, XTO Energy drilled 16 gross (10.6 net) wells and performed 28 workovers in 2008. XTO Energy has informed the trustee that it plans to drill up to 8 wells and perform up to 10 workovers in Major County during 2009. In Woodward County, XTO Energy drilled 11 gross (8.7 net) wells and performed 5 workovers in 2008. XTO Energy has informed the trustee that it plans to drill up to 8 wells and perform up to 4 workovers in Woodward County during 2009.

In the Elk City field, XTO Energy drilled 1 gross (0.9 net) wells and performed 7 workovers in 2008. XTO Energy has informed the trustee that it does not plan to drill any new wells and will perform 3 workovers within the Elk City field during 2009.

Green River Basin

The Green River Basin is located in southwestern Wyoming. Natural gas was discovered in the Fontenelle Field of the Green River Basin in the early 1970s. The producing reservoirs are the Frontier, Baxter and Dakota sandstones. Gas sales volumes from the underlying properties in the Green River Basin were 7.6 Bcf in 2008, or approximately 27% of total sales volumes from the underlying properties.

In 2008, XTO Energy completed 7 gross (7.0 net) wells and performed 9 workovers. XTO Energy has informed the trustee that it does not plan to drill any new wells and will perform up to 6 workovers in the

5

Green River Basin during 2009. XTO Energy has informed the trustee that it is continuing its efforts to reduce pipeline pressure which has shown potential for increasing production and extending field life in the Fontenelle Field.

Estimated Proved Reserves and Future Net Cash Flows

The following are proved reserves of the underlying properties, as estimated by independent engineers, and proved reserves and future net cash flows from proved reserves of the net profits interests, based on an allocation of these reserves, at December 31, 2008:

	Underlying Properties				Net Profits Interests
	Proved Reserves(a)				Proved Reserves(a)(b)				Future Net Cash Flows from Proved Reserves(a)(c)
	Gas (Mcf)		Oil (Bbls)		Gas (Mcf)		Oil (Bbls)		Undiscounted		Discounted
(in Thousands)
Oklahoma		240,591		3,126		123,040		1,600	$	598,138	$	302,085
Wyoming		100,832		110		44,040		48		168,079		86,264
Kansas		24,882		73		11,403		34		41,116		23,451
TOTAL		366,305		3,309		178,483		1,682	$	807,333	$	411,800

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

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

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

6

TRUSTEE’S DISCUSSION AND ANALYSIS

Years Ended December 31, 2008, 2007 and 2006

Net profits income for 2008 was $117,268,069, as compared with $70,499,584 for 2007 and $91,241,196 for 2006. The 66% increase in net profits income from 2007 to 2008 is primarily the result of higher oil and gas prices and increased oil production, partially offset by increased production expense, higher taxes, transportation and other costs and higher development costs. The 23% decrease in net profits income from 2006 to 2007 was primarily the result of lower gas sales volumes and gas prices, partially offset by lower development costs. Approximately 85% in 2008, 88% in 2007 and 91% in 2006 of net profits income was derived from natural gas sales.

Trust administration expense was $864,872 in 2008 as compared to $1,246,189 in 2007 and $528,978 in 2006. Administration expense decreased 31% from 2007 to 2008 primarily because of lower costs related to unitholder tax reporting, as a result of a decrease in the number of unitholders, and the timing of expenditures. Administration expense increased significantly from 2006 to 2007 primarily because of additional unitholder tax reporting, an increased number of unitholders and the timing of expenditures. Interest income was $91,203 in 2008, $135,125 in 2007 and $198,542 in 2006. Changes in interest income are attributable to fluctuations in net profits income and interest rates. Distributable income was $116,494,400 or $2.912360 per unit in 2008, $69,388,520 or $1.734713 per unit in 2007 and $90,910,760 or $2.272769 per unit in 2006.

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

• oil and gas sales volumes,

• oil and gas sales prices, and

• costs deducted in the calculation of net profits income.

Volumes

From 2007 to 2008, underlying gas sales volumes remained flat as increased production from new wells and workovers was offset by natural production decline. Underlying oil sales volumes increased 12% from 2007 to 2008 primarily because of increased production from new wells and workovers and prior period volume adjustments in 2007, partially offset by natural production decline. From 2006 to 2007, underlying gas sales volumes decreased 5% and underlying oil sales volumes decreased 8%. Lower gas and oil sales volumes were primarily because of natural production decline, partially offset by increased production from new wells and workovers and the timing of cash receipts. In addition, oil sales volumes were lower because of the effects of prior period volume adjustments in 2007.

Prices

Gas.  The 2008 average gas price was $7.75 per Mcf, a 36% increase from the 2007 average gas price of $5.70 Mcf, which was 14% lower than the 2006 average gas price of $6.59 per Mcf. Beginning in 2006 and into 2007, gas prices trended lower primarily because of an adequate natural gas supply inventory due to the warmer than normal winter weather in 2006 and the absence of hurricane activity in the Gulf of Mexico. Much colder temperatures in early 2007 caused prices to partially rebound. As a result of tighter storage levels and higher oil prices, gas prices increased in the first half of 2008 and reached as high as $13.00 per MMBtu in July. Due to concerns of oversupply from shale gas development, declining demand due to the deepening U.S. recession, falling oil prices and increased gas storage, recent gas prices have declined. Natural gas prices are expected to remain volatile.

Gas prices in the Rocky Mountain region were significantly lower for September through November 2008 and April through November 2007 production primarily as a result of scheduled pipeline maintenance in 2008, as well as, pipeline constraints and limited regional demand. This resulted in lower realized prices for the trust’s Wyoming gas production for the November 2008 through January 2009 and June 2007 through January 2008 distributions which, in turn, resulted in excess costs on properties underlying the Wyoming net profits interests (see “Excess costs” below). The onset of winter demand and the completion of scheduled

7

pipeline maintenance have led to a partial rebound of Rocky Mountain gas prices. At February 18, 2009, the average futures price for Wyoming gas for the following six months is expected to be approximately 31% lower than the NYMEX price. Wyoming gas production was approximately 27% of total trust gas production for the year ended December 31, 2008.

The trust’s average realized gas price was $7.75 per Mcf, 15% lower than the average NYMEX price of $9.13 in 2008; $5.70 per Mcf, 18% lower than the average NYMEX price of $6.94 in 2007; and $6.59 per Mcf, or 18%, lower than the average NYMEX price of $8.02 in 2006. The average NYMEX price for November 2008 through January 2009 was $6.50 per MMBtu. At February 18, 2009, the average NYMEX gas price for the following 12 months was $4.97 per MMBtu. Recent trust gas prices have averaged approximately 44% lower than the NYMEX price.

Oil.  The average oil price for 2008 was $104.62 per Bbl, 63% higher than the average oil price for 2007 of $64.35 per Bbl, which was 1% higher than the average oil price for 2006 of $63.73 per Bbl. Oil prices have risen primarily because of increasing global demand and supply shortage concerns, inadequate sour crude refining capacity, reduced production as a result of tropical storms and political instability in some oil producing countries. In the last few months of 2007 and the first half of 2008, narrowing excess worldwide capacity, weakness in the dollar and continuing tension in the Middle East caused prices to reach record levels above $147.00 per Bbl in July 2008. However, lower demand as a result of the deepening U.S. recession and slowing global economy, the tightened credit markets and rising crude oil supplies have caused oil prices to decline sharply in the second half of 2008. Oil prices are expected to remain volatile. The average NYMEX price for November 2008 through January 2009 was $46.91 per Bbl. At February 18, 2009, the average NYMEX oil price for the following 12 months was $42.98 per Bbl. Recent trust oil prices have averaged approximately 4% lower than the NYMEX price.

Costs

The calculation of net profits income includes deductions for production expense, development costs and overhead since the related underlying properties are working interests. If monthly costs exceed revenues for any state, these excess costs must be recovered, with accrued interest, from future net proceeds of that state and cannot reduce net profits income from another state. See “Excess costs” below.

Taxes, Transportation and Other.  Taxes, transportation and other generally fluctuates with changes in total revenues. Taxes, transportation and other increased 26% from 2007 to 2008 primarily because of increased production taxes related to higher revenues, partially offset by decreased property taxes. Taxes, transportation and other decreased 8% from 2006 to 2007 primarily because of decreased production taxes related to lower revenues, partially offset by increased purchaser deductions.

Production.  Production expense increased 23% from 2007 to 2008 primarily because of overall price increases as well as increased location, repairs and maintenance, fuel, compressor rentals and labor costs, partially offset by mechanical and marketing rebates. Production expense was relatively unchanged from 2006 to 2007 as increased labor and compressor rental costs were largely offset by decreased fuel costs.

Development.  Development costs deducted were $46.0 million in 2008, $42.8 million in 2007 and $51.7 million in 2006. In 2008, actual development costs were $52.6 million. At December 31, 2008, cumulative actual costs exceeded cumulative budgeted costs by approximately $7.3 million. The development cost deduction was lowered to $3.75 million per month beginning with the February 2007 distribution. Due to lower than anticipated actual costs as a result of the timing of expenditures, the development cost deduction was lowered to $2.0 million for the April and May 2007 distributions, but was increased to $3.75 million with the June 2007 distribution and was maintained at $3.75 million for the remainder of 2007 through the August 2008 distribution. Due to higher than anticipated costs as a result of the timing of expenditures, the monthly development cost deduction was increased to $4.0 million beginning with the September 2008 distribution and was maintained at that level for the remainder of 2008. XTO Energy has advised the trustee that this monthly deduction will continue to be evaluated and revised as necessary.

Overhead.  Overhead is charged by XTO Energy for administrative expenses incurred to support operations of the underlying properties. Overhead fluctuates based on changes in the active well count and drilling activity on the underlying properties, as well as an annual cost level adjustment.

8

Excess Costs.  Costs exceeded revenues by $970,780 ($776,624 net to the trust) on properties underlying the Wyoming net profits interests in November 2008. Scheduled pipeline maintenance and limited regional demand led to lower realized gas prices for production in the Rocky Mountain region (see “Prices” above). These lower gas prices caused costs to exceed revenues on properties underlying the Wyoming net profits interest, however, these excess costs did not reduce net proceeds from the remaining conveyances. XTO Energy has advised the trustee that the onset of winter demand and completion of scheduled pipeline maintenance led to a partial rebound of Rocky Mountain gas prices, resulting in the full recovery of excess costs plus accrued interest of $3,192 ($2,554 net to the trust) in December 2008.

Costs exceeded revenues by $853,468 ($682,774 net to the trust) on properties underlying the Wyoming net profits interests in November and December 2007. Limited pipeline capacity and moderate regional demand led to lower realized gas prices for production in the Rocky Mountain region (see “Prices” above). These lower gas prices caused costs to exceed revenues on properties underlying the Wyoming net profits interest, however, these excess costs did not reduce net proceeds from the remaining conveyances. XTO Energy advised the trustee that with winter demand and the completion of the first phase of a major pipeline expansion in January 2008, Rocky Mountain gas prices increased and the excess costs, plus accrued interest of $10,090 ($8,072 net to the trust), was fully recovered by February 2008.

Fourth Quarter 2008 and 2007

During fourth quarter 2008 the trust received net profits income totaling $17,591,558 compared with fourth quarter 2007 net profits income of $14,642,197. This 20% increase in net profits income was primarily due to increased oil and gas prices, partially offset by decreased oil and gas volumes and increased production expense.

Administration expense was $127,280 and interest income was $17,402, resulting in fourth quarter 2008 distributable income of $17,481,680, or $0.437042 per unit. Distributable income for fourth quarter 2007 was $14,565,560 or $0.364139 per unit. Distributions to unitholders for the quarter ended December 31, 2008 were:

Record Date	Payment Date		Per Unit
October 31, 2008		November 17, 2008		$0.274018
November 28, 2008		December 12, 2008		0.134378
December 31, 2008		January 15, 2009		0.028646
				$0.437042

Volumes

Fourth quarter underlying gas sales volumes decreased 6% and underlying oil sales volumes decreased 5% from 2007 to 2008. Gas and oil sales volumes decreased primarily because of natural production decline and the timing of cash receipts, partially offset by increased production from new wells and workovers.

Prices

The average fourth quarter 2008 gas price was $6.03 per Mcf, or 26% higher than the fourth quarter 2007 average price of $4.77 per Mcf. The average fourth quarter 2008 oil price was $91.81 per Bbl, or 22% higher than the fourth quarter 2007 average price of $75.10 per Bbl. For further information about product prices, see “Years Ended December 31, 2008, 2007 and 2006 — Prices” above.

Costs

Taxes, Transportation and Other.  Taxes, transportation and other generally fluctuates with changes in total revenues. Taxes, transportation and other increased 7% from 2007 to 2008 primarily due to the 18% increase in total revenues over the same period, partially offset by decreased property taxes.

Production.  Fourth quarter production expense increased 30% from 2007 to 2008 primarily because of overall price increases as well as increased compressor rentals, location, maintenance and fuel costs.

Development.  Development costs, which were deducted based on budgeted development costs, increased 7% from fourth quarter 2007 to 2008 primarily because of the timing of expenditures.

Overhead.  Overhead increased 10% from fourth quarter 2007 to 2008 primarily because of the annual rate adjustment based on an oil and gas industry index.

9

Excess Costs.  Costs exceeded revenues by $970,780 ($776,624 net to the trust) on properties underlying the Wyoming net profits interests in November 2008. Scheduled pipeline maintenance and limited regional demand led to lower realized gas prices for production in the Rocky Mountain region (see “Years Ended December 31, 2008, 2007 and 2006 — Prices” above). These lower gas prices caused costs to exceed revenues on properties underlying the Wyoming net profits interests, however, these excess costs did not reduce net proceeds from the remaining conveyances. XTO Energy has advised the trustee that the onset of winter demand and the completion of scheduled pipeline maintenance led to a partial rebound of Rocky Mountain gas prices, resulting in the full recovery of excess costs plus accrued interest of $3,192 ($2,554 net to the trust) in December 2008.

Costs exceeded revenues by $853,468 ($682,774 net to the trust) on properties underlying the Wyoming net profits interests in November and December 2007. Limited pipeline capacity and moderate regional demand led to lower realized gas prices for production in the Rocky Mountain region (see “Prices” above). These lower gas prices caused costs to exceed revenues on properties underlying the Wyoming net profits interest, however, these excess costs did not reduce net proceeds from the remaining conveyances. XTO Energy advised the trustee that with the onset of winter demand and the completion of the first phase of a major pipeline expansion in January 2008, Rocky Mountain gas prices increased and the excess costs, plus accrued interest of $10,090 ($8,072 net to the trust), was fully recovered by February 2008.

For further information about costs, see “Years Ended December 31, 2008, 2007 and 2006 — Costs” above.

See Item 7 of the accompanying Form 10-K for disclosures regarding liquidity and capital resources, off-balance sheet arrangements, contractual obligations and commitments, related party transactions and critical accounting policies of the trust. See Item 7A of the accompanying Form 10-K for quantitative and qualitative disclosures about market risk affecting the trust.

10

Calculation of Net Profits Income

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

	Year Ended December 31(a)								Three Months Ended December 31(a)
	2008		2007			2006			2008		2007
Sales Volumes
Gas (Mcf)(b)
Underlying properties		28,176,094		28,092,224			29,628,079			6,808,017		7,253,325
Average per day		76,984		76,965			81,173			74,000		78,840
Net profits interests		13,134,564		11,233,503			12,871,453			2,218,747		2,413,294
Oil (Bbls)(b)
Underlying properties		341,754		305,594			332,525			77,975		82,039
Average per day		934		837			911			848		892
Net profits interests		169,915		140,805			145,230			29,676		34,495
Average Sales Prices
Gas (per Mcf)		$ 7.75		$ 5.70			$ 6.59			$ 6.03		$ 4.77
Oil (per Bbl)		$ 104.62		$ 64.35			$ 63.73			$ 91.81		$ 75.10
Revenues
Gas sales		$218,253,910		$160,104,931			$195,130,332			$41,058,215		$34,589,223
Oil sales		35,754,556		19,666,471			21,190,530			7,158,846		6,160,932
Total Revenues		254,008,466		179,771,402			216,320,862			48,217,061		40,750,155
Costs
Taxes, transportation and other		23,271,226		18,429,983			20,074,451			4,643,403		4,333,853
Production expense		27,454,543		22,268,104			22,231,559			7,028,920		5,391,813
Development costs(c)		46,000,000		42,750,000			51,700,000			12,000,000		11,250,000
Overhead		9,830,861		9,052,303			8,263,357			2,552,099		2,325,211
Excess costs(d)		866,750		(853,468	)		—			3,192		(853,468	)
Total Costs		107,423,380		91,646,922			102,269,367			26,227,614		22,447,409
Net Proceeds		146,585,086		88,124,480			114,051,495			21,989,447		18,302,746
Net Profits Percentage		80%		80	%		80	%		80%		80	%
Net Profits Income		$117,268,069		$70,499,584			$91,241,196			$17,591,558		$14,642,197

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

(b) Oil and gas sales volumes are allocated to the net profits interests based upon a formula that considers oil and gas prices and the total amount of production expense and development costs. Changes in any of these factors may result in disproportionate fluctuations in volumes allocated to the net profits interests. Therefore, comparative discussion of oil and gas sales volumes is based on the underlying properties.

(c) See Note 5 to Financial Statements.

(d) See Note 4 to Financial Statements.

11

HUGOTON ROYALTY TRUST

STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS

	December 31
	2008		2007
Assets
Cash and short-term investments		$1,145,840		$5,214,000
Net profits interests in oil and gas properties – net (Notes 1 and 2)		146,722,015		155,820,033
		$147,867,855		$161,034,033
Liabilities and Trust Corpus
Distribution payable to unitholders		$1,145,840		$5,214,000
Trust corpus (40,000,000 units of beneficial interest authorized and outstanding)		146,722,015		155,820,033
		$147,867,855		$161,034,033

STATEMENTS OF DISTRIBUTABLE INCOME

	Year Ended December 31
	2008		2007		2006
Net profits income		$117,268,069		$70,499,584		$91,241,196
Interest income		91,203		135,125		198,542
Total income		117,359,272		70,634,709		91,439,738
Administration expense		864,872		1,246,189		528,978
Distributable income		$116,494,400		$69,388,520		$90,910,760
Distributable income per unit (40,000,000 units)		$2.912360		$1.734713		$2.272769

STATEMENTS OF CHANGES IN TRUST CORPUS

	Year Ended December 31
	2008		2007		2006
Trust corpus, beginning of year		$155,820,033		$163,796,772		$171,935,330
Amortization of net profits interests		(9,098,018)		(7,976,739)		(8,138,558)
Distributable income		116,494,400		69,388,520		90,910,760
Distributions declared		(116,494,400)		(69,388,520)		(90,910,760)
Trust corpus, end of year		$146,722,015		$155,820,033		$163,796,772

 
 
See Accompanying Notes to Financial Statements.

12

HUGOTON ROYALTY TRUST
  
NOTES TO FINANCIAL STATEMENTS

1. Trust Organization and Provisions

Hugoton Royalty Trust was created on December 1, 1998 by XTO Energy Inc. (formerly known as “Cross Timbers Oil Company”). Effective on that date, XTO Energy conveyed 80% net profits interests in certain predominantly gas-producing working interest properties in Kansas, Oklahoma and Wyoming to the trust under separate conveyances for each of the three states. In exchange for the conveyances of the net profits interests to the trust, XTO Energy received 40 million units of beneficial interest in the trust. The trust’s initial public offering was in April 1999. The majority of the underlying working interest properties are currently owned and operated by XTO Energy (Note 7).

Bank of America, N.A. is the trustee for the trust. In 2007 the Bank of America private wealth management group officially became known as “U.S. Trust, Bank of America Private Wealth Management.” The legal entity that serves as the trustee of the trust did not change, and references in this Annual Report to U.S. Trust, Bank of America Private Wealth Management shall describe the legal entity Bank of America, N.A. The trust indenture provides, among other provisions, that:

• the trust cannot engage in any business activity or acquire any assets other than the net profits interests and specific short-term cash investments;

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

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

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

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

• the trust will terminate upon the first occurrence of:

— disposition of all net profits interests pursuant to terms of the trust indenture,

— gross proceeds from the underlying properties falling below $1 million per year for two successive years, or

— a vote of 80% of the unitholders to terminate the trust in accordance with provisions of the trust indenture.

2. Basis of Accounting

The financial statements of the trust are prepared on the following basis and are not intended to present financial position and results of operations in conformity with U.S. generally accepted accounting principles:

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

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

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

The most significant differences between the trust’s financial statements and those prepared in accordance with U.S. generally accepted accounting principles are:

13

HUGOTON ROYALTY TRUST
  
NOTES TO FINANCIAL STATEMENTS

2. Basis of Accounting  – (continued)

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

• Expenses are recognized when paid rather than when incurred.

• Cash reserves may be established by the trustee for contingencies that would not be recorded under U.S. generally accepted accounting principles.

This comprehensive basis of accounting corresponds to the accounting permitted for royalty trusts by the U.S. Securities and Exchange Commission, as specified by Staff Accounting Bulletin Topic 12:E, Financial Statements of Royalty Trusts.

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

In December 2008, the Securities and Exchange Commission (SEC) released Final Rule, Modernization of Oil and Gas Reporting. The new disclosure requirements include provisions that permit the use of new technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserves volumes. The new requirements also will allow companies to disclose their probable and possible reserves to investors. In addition, the new disclosure requirements require companies to: (a) report the independence and qualifications of its reserves preparer or auditor; (b) file reports when a third party is relied upon to prepare reserves estimates or conducts a reserves audit; and (c) report oil and gas reserves using an average price based upon the prior 12-month period rather than year-end prices. The new disclosure requirements are effective for financial statements for fiscal years ending on or after December 31, 2009. The effect of adopting the SEC rule has not been determined, but it is not expected to have a significant effect on our reported financial position or distributable income.

The initial carrying value of the net profits interests of $247,066,951 was XTO Energy’s historical net book value of the interests on December 1, 1998, the date of the transfer to the trust. Amortization of the net profits interests is calculated on a unit-of-production basis and charged directly to trust corpus. Accumulated amortization was $100,344,936 as of December 31, 2008 and $91,246,918 as of December 31, 2007.

3. Distributions to Unitholders

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

Net profits income received by the trustee consists of net proceeds received in the prior month by XTO Energy from the underlying properties, multiplied by 80%. Net proceeds are the gross proceeds received from the sale of production, less costs. Costs generally include applicable taxes, transportation, legal and marketing charges, production expense, development and drilling costs, and overhead (Note 7).

XTO Energy, as owner of the underlying properties, computes net profits income separately for each of the three conveyances (one for each of the states of Kansas, Oklahoma and Wyoming). If costs exceed revenues for any conveyance, such excess costs must be recovered, with accrued interest, from future net proceeds of that conveyance and cannot reduce net profits income from the other conveyances (Note 4).

14

HUGOTON ROYALTY TRUST
  
NOTES TO FINANCIAL STATEMENTS

4. Excess Costs

Costs exceeded revenues by $970,780 ($776,624 net to the trust) on properties underlying the Wyoming net profits interests in November 2008. Scheduled pipeline maintenance and limited regional demand led to lower realized gas prices for production in the Rocky Mountain region. These lower gas prices caused costs to exceed revenues on properties underlying the Wyoming net profits interest, however, these excess costs did not reduce net proceeds from the remaining conveyances. XTO Energy has advised the trustee that the onset of winter demand and completion of scheduled pipeline maintenance led to a partial rebound of Rocky Mountain gas prices, resulting in the full recovery of excess costs plus accrued interest of $3,192 ($2,554 net to the trust) in December 2008.

Costs exceeded revenues by $853,468 ($682,774 net to the trust) on properties underlying the Wyoming net profits interests in November and December 2007. Limited pipeline capacity and moderate regional demand led to lower realized gas prices for production in the Rocky Mountain region (see “Prices” above). These lower gas prices caused costs to exceed revenues on properties underlying the Wyoming net profits interest, however, these excess costs did not reduce net proceeds from the remaining conveyances. XTO Energy advised the trustee that with the onset of winter demand and the completion of the first phase of a major pipeline expansion in January 2008, Rocky Mountain gas prices increased and the excess costs, plus accrued interest of $10,090 ($8,072 net to the trust), was fully recovered by February 2008.

5. Development Costs

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

	Year Ended December 31
	2008		2007		2006
Cumulative actual costs (over) under the amount deducted – beginning of period		$(675,754)		$(3,410,174)		$113,905
Actual costs		(52,638,330)		(40,015,580)		(55,224,079)
Budgeted costs deducted		46,000,000		42,750,000		51,700,000
Cumulative actual costs (over) under the amount deducted – end of period		$(7,314,084)		$(675,754)		$(3,410,174)

The development cost deduction was lowered to $3.75 million per month beginning with the February 2007 distribution. Due to lower than anticipated actual costs as a result of the timing of expenditures, the development cost deduction was lowered to $2.0 million for the April and May 2007 distributions, but was increased to $3.75 million with the June 2007 distribution and was maintained at $3.75 million for the remainder of 2007 through the August 2008 distribution. Due to higher than anticipated costs as a result of the timing of expenditures, the monthly development cost deduction was increased to $4.0 million beginning with the September 2008 distribution and was maintained at that level for the remainder of 2008. XTO Energy has advised the trustee that this monthly deduction will continue to be evaluated and revised as necessary.

6. Federal Income Taxes

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

For federal income tax purposes, unitholders of a grantor trust are considered to own the trust’s income and principal as though no trust were in existence. The income of the trust is deemed to be received or accrued by the unitholders at the time such income is received or accrued by the trust, rather than when distributed by the trust.

15

HUGOTON ROYALTY TRUST
  
NOTES TO FINANCIAL STATEMENTS

6. Federal Income Taxes  – (continued)

The trust is a widely held fixed investment trust (“WHFIT”) classified as a non-mortgage widely held fixed investment trust (“NMWHFIT”) for federal income tax purposes. The trustee is the representative of the trust that will provide tax information in accordance with the applicable U.S. Treasury Regulations governing the information reporting requirements of the trust as a WHFIT or a NMWHFIT.

7. XTO Energy Inc.

XTO Energy operates approximately 94% of the underlying properties. In computing net proceeds, XTO Energy deducts an overhead charge for reimbursement of administrative expenses on the underlying properties it operates. As of December 31, 2008, the overhead charge was approximately $850,000 ($680,000 net to the trust) per month and is subject to annual adjustment based on an oil and gas industry index as defined in the trust agreement.

In April and May 1999, XTO Energy sold 17 million trust units in the trust’s initial public offering, and later in 1999 and 2000, sold 1.3 million trust units to certain of its officers. The trust did not receive the proceeds from these sales of trust units. In May 2006, XTO Energy distributed all of its remaining 21.7 million trust units as a dividend to its common stockholders. XTO Energy currently is not a unitholder of the trust.

XTO Energy sells a significant portion of natural gas production from the underlying properties to certain of XTO Energy’s wholly owned subsidiaries under contracts in existence when the trust was created, generally at amounts approximating monthly published market prices. Most of the production from the Hugoton area is sold under a contract to Timberland Gathering & Processing Company, Inc. (“TGPC”) based on the index price. Much of the gas production in Major County, Oklahoma is sold to Ringwood Gathering Company (“RGC”), which retains approximately $0.31 per Mcf as a compression and gathering fee. TGPC and RGC sell gas to Cross Timbers Energy Services, Inc. (“CTES”), which markets gas to third parties. XTO Energy sells directly to CTES most gas production not sold directly to TGPC or RGC.

Total gas sales from the underlying properties to XTO Energy’s wholly owned subsidiaries were $103.3 million for 2008, or 47% of total gas sales, $76.6 million for 2007, or 48% of total gas sales and $103.2 million for 2006, or 53% of total gas sales.

8. Contingencies

Litigation

On October 17, 1997, an action, styled United States of America ex rel. Grynberg v. Cross Timbers Oil Company, et al., was filed in the United States District Court for the Western District of Oklahoma by Jack J. Grynberg on behalf of the United States under the qui tam provisions of the U.S. False Claims Act against XTO Energy. The plaintiff alleges that XTO Energy underpaid royalties on natural gas produced from federal leases and lands owned by Native Americans in amounts in excess of 20% as a result of mismeasuring the volume of natural gas, incorrectly analyzing its heating content and improperly valuing the natural gas during at least the past ten years. The plaintiff seeks treble damages for the unpaid royalties (with interest, attorney’s fees and expenses), civil penalties between $5,000 and $10,000 for each violation of the U.S. False Claims Act, and an order for XTO Energy to cease the allegedly improper measuring practices. This lawsuit against XTO Energy and similar lawsuits filed by Grynberg against more than 300 other companies was consolidated in the United States District Court for Wyoming. In October 2002, the court granted a motion to dismiss Grynberg’s royalty valuation claims, and Grynberg’s appeal of this decision was dismissed for lack of appellate jurisdiction in May 2003. In response to a motion to dismiss filed by XTO Energy and other defendants, in October 2006 the district judge held that Grynberg failed to establish the jurisdictional requirements to maintain the action against XTO Energy and other defendants and dismissed the actions for lack of subject matter jurisdiction. Grynberg has filed an appeal of this decision. While XTO Energy is unable to predict the final outcome of this case or estimate the amount of any possible loss, it has informed the trustee that it

16

HUGOTON ROYALTY TRUST
  
NOTES TO FINANCIAL STATEMENTS

8. Contingencies  – (continued)

believes that the allegations of this lawsuit are without merit and intends to vigorously defend the action. However, an order to change measuring practices or a related settlement could adversely affect the trust by reducing net proceeds in the future by an amount that is presently not determinable, but, in XTO Energy management’s opinion, is not currently expected to be material to the trust’s annual distributable income, financial position or liquidity.

An amended petition for a class action lawsuit, Beer, et al. v. XTO Energy Inc., was filed in January 2006, in the District Court of Texas County, Oklahoma by royalty owners of natural gas wells in Oklahoma. The plaintiffs allege that XTO Energy has not properly accounted to the plaintiffs for the royalties to which they are entitled and seek an accounting regarding the natural gas and other products produced from their wells and the prices paid for the natural gas and other products produced, and for payment of the monies allegedly owed since June 2002, with a certain limited number of plaintiffs claiming monies owed for additional time. XTO Energy removed the case to federal district court in Oklahoma City. A hearing on the class certification was conducted in October 2008. No decision has been made. The plaintiffs have not alleged in their petition an amount that they are seeking. XTO Energy has informed the trustee that it believes that it has strong defenses to this lawsuit and intends to vigorously defend its position. However, if XTO Energy ultimately makes any settlement payments or receives a judgment against it, the trust will bear its 80% share of such settlement or judgment related to production from the underlying properties. Additionally, if a judgment or settlement increases the amount of future payments to royalty owners, the trust would bear its proportionate share of the increased payments through reduced net proceeds. XTO Energy has informed the trustee that, although the amount of any reduction in net proceeds is not presently determinable, in its management’s opinion, the amount is not currently expected to be material to the trust’s annual distributable income, financial position or liquidity.

In September 2008, a class action lawsuit was filed against XTO Energy styled Wallace B. Roderick Revocable Living Trust, et al. v. XTO Energy Inc. in the District Court of Kearny County, Kansas. XTO Energy removed the case to federal court in Wichita, Kansas. The plaintiffs allege that XTO Energy has improperly taken post-production costs from royalties paid to the plaintiffs from wells located in Kansas, Oklahoma and Colorado. The plaintiffs also seek to represent all royalty owners in these three states as a class. The plaintiff’s claims overlap the claims made by the plaintiffs in the Beer case as to certain properties. XTO Energy has answered and denied all claims. XTO Energy has informed the trustee that it believes that XTO Energy has strong defenses to this lawsuit and intends to vigorously defend its position. However, if XTO Energy ultimately makes any settlement payments or receives a judgment against it, the trust will bear its 80% share of such settlement or judgment related to production from the underlying properties. Additionally, if the judgment or settlement increases the amount of future payments to royalty owners, the trust would bear its proportionate share of the increased payments through reduced net proceeds. XTO Energy has informed the trustee that, although the amount of any reduction in net proceeds is not presently determinable, in its management’s opinion, the amount is not currently expected to be material to the trust’s annual distributable income, financial position or liquidity.

Certain of the underlying properties are involved in various other lawsuits and certain governmental proceedings arising in the ordinary course of business. XTO Energy has advised the trustee that it does not believe that the ultimate resolution of these claims will have a material effect on trust annual distributable income, financial position or liquidity.

Other

Several states have enacted legislation to require state income tax withholding from nonresident recipients of oil and gas proceeds. After consultation with its state tax counsel, XTO Energy has advised the trustee that it believes the trust is not subject to these withholding requirements. However, regulations could be issued by the various states which could change this conclusion. Should the trust be required to withhold state taxes,

17

HUGOTON ROYALTY TRUST
  
NOTES TO FINANCIAL STATEMENTS

8. Contingencies  – (continued)

distributions to the unitholders would be reduced by the required amount, subject to the unitholder’s right to file a state tax return to claim any refund due.

9. Supplemental Oil and Gas Reserve Information (Unaudited)

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

10. Quarterly Financial Data (Unaudited)

The following is a summary of net profits income, distributable income and distributable income per unit by quarter for 2008 and 2007:

	Net Profits Income		Distributable Income		Distributable Income per Unit
2008
First Quarter		$22,035,854		$21,769,160		$0.544229
Second Quarter		33,899,248		33,554,920		0.838873
Third Quarter		43,741,409		43,688,640		1.092216
Fourth Quarter		17,591,558		17,481,680		0.437042
		$117,268,069		$116,494,400		$2.912360
2007
First Quarter		$16,735,385		$16,242,280		$0.406057
Second Quarter		21,251,246		20,846,000		0.521150
Third Quarter		17,870,756		17,734,680		0.443367
Fourth Quarter		14,642,197		14,565,560		0.364139
		$70,499,584		$69,388,520		$1.734713

18

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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

We have audited the accompanying statements of assets, liabilities, and trust corpus of the Hugoton Royalty Trust as of December 31, 2008 and 2007 and related statements of distributable income and changes in trust corpus for each of the years in the three-year period ended December 31, 2008. We also have audited Hugoton Royalty Trust’s internal control over financial reporting as of December 31, 2008, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The trustee of Hugoton Royalty Trust is responsible for these financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on these financial statements and an opinion on the trust’s internal control over financial reporting based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by the trustee, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

As described in note 2 to the financial statements, these financial statements were prepared on the modified cash basis of accounting, which is a comprehensive basis of accounting other than accounting principles generally accepted in the United States of America.

The trust’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with the modified cash basis of accounting. The trust’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the trust; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with the modified cash basis of accounting, and that receipts and expenditures of the trust are being made only in accordance with authorizations of the trustee; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the trust’s assets that could have a material effect on the financial statements.

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

In our opinion, the financial statements referred to above present fairly, in all material respects, the assets, liabilities, and trust corpus of Hugoton Royalty Trust as of December 31, 2008 and 2007, and its distributable income and changes in trust corpus for each of the years in the three-year period ended December 31, 2008, in conformity with the modified cash basis of accounting described in note 2. Also in our opinion, Hugoton Royalty Trust maintained, in all material respects, effective internal control over financial reporting as of December 31, 2008, based on control criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

KPMG LLP

Fort Worth, Texas
February 25, 2009

19

HUGOTON ROYALTY TRUST

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

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

WEB SITE

www.hugotontrust.com

AUDITORS

KPMG LLP
Fort Worth, Texas

LEGAL COUNSEL

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

TAX COUNSEL

Winstead PC
Houston, Texas

TRANSFER AGENT AND REGISTRAR

BNY Mellon Shareowner Services
www.bnymellon.com/shareowner

20

EX-23.1

EXHIBIT 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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

We consent to the incorporation by reference in Registration Statement No. 333-81849 on Form S-8 of XTO Energy Inc. of our report dated February 25, 2009, with respect to the statements of assets, liabilities, and trust corpus of the Hugoton Royalty Trust as of December 31, 2008 and 2007, and the related statements of distributable income and changes in trust corpus for each of the years in the three-year period ended December 31, 2008, and the effectiveness of internal control over financial reporting as of December 31, 2008, which report appears in the December 31, 2008 Annual Report on Form 10-K of the Hugoton Royalty Trust.

KPMG LLP

Fort Worth, Texas
February 25, 2009

EX-23.2

EXHIBIT 23.2

[LETTERHEAD OF MILLER AND LENTS, LTD. APPEARS HERE]

February 25, 2009

Hugoton Royalty Trust
P.O. Box 830650
Dallas, TX 75283-0650

Re: Hugoton Royalty Trust
2008 Annual Report on Form 10-K

Gentlemen:

The firm of Miller and Lents, Ltd., consents to the references to our firm in the form and context in which they appear and to the use of our report dated February 20, 2009, regarding the Hugoton Royalty Trust Proved Reserves and Future Net Revenue as of December 31, 2008, in the 2008 Annual Report on Form 10-K. We further consent to the incorporation by reference in Registration Statement No. 333-81849 on Form S-8 of XTO Energy Inc.

Miller and Lents, Ltd., has no interests in the Hugoton Royalty Trust or in any affiliated companies or subsidiaries and is not to receive any such interest as payment for such reports and has no director, officer, or employee otherwise connected with Hugoton Royalty Trust. We are not employed by Hugoton Royalty Trust on a contingent basis.

Yours very truly,

MILLER AND LENTS, LTD.

By /s/ James C. Pearson
James C. Pearson
Chairman

EX-31

EXHIBIT 31

CERTIFICATIONS

I, Nancy G. Willis, certify that:

1. I have reviewed this annual report on Form 10-K of Hugoton Royalty Trust, for which Bank of America, N.A. acts as Trustee;

2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;

3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, distributable income and changes in trust corpus of the registrant as of, and for, the periods presented in this annual report;

4. I am responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)), for the registrant and I have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under my supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to me by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under my supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report my conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. I have disclosed, based on my most recent evaluation of internal control over financial reporting, to the registrant’s auditors:

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

In giving the certifications in paragraphs 4 and 5 above, I have relied to the extent I consider reasonable on information provided to me by XTO Energy Inc.

By /s/ Nancy G. Willis
Nancy G. Willis
Vice President
Bank of America, N.A.

Date: February 25, 2009

EX-32

EXHIBIT 32

CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of Hugoton Royalty Trust (the “Trust”) on Form 10-K for the year ended December 31, 2008 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), the undersigned, not in its individual capacity but solely as the trustee of the Trust, certifies pursuant to 18 U.S.C. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to its knowledge:

(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Trust.

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

February 25, 2009 By: /s/ Nancy G. Willis
Nancy G. Willis
Vice President