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, 2006

Commission file number 1-10476

Hugoton Royalty Trust

For the fiscal year ended December 31, 2007

Commission file number 1-10476

HUGOTON ROYALTY TRUST

(Exact nameName of registrantRegistrant as specifiedSpecified in the Hugoton Royalty Trust Indenture)

Texas

58-6379215

Texas

58-6379215
(State or other jurisdictionOther Jurisdiction of
incorporation or organization)

(I.R.S. Employer

Incorporation or Organization)Identification No.)

Bank of America, N.A.

75283-0650

Trustee

(Zip Code)

P.O. Box 830650

Dallas, Texas

(Address of principal executive offices)

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)

Registrant’s telephone number including area 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

Each Class

Name of each exchangeEach Exchange on which registered


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. Yesx  No  NOo

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

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. Yesx  No   NOo

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.ox

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

Large accelerated filer x  Accelerated filer o  Non-accelerated filer o

Large accelerated filer xAccelerated 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). Yeso No NOx

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, 200629, 2007 (the last business day of its most recently completed second fiscal quarter), held by non-affiliates of the registrant on that date was approximately $1.15 billion.$976 million.

At February 28, 2007,25, 2008, 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:

20062007 Annual Report to Unitholders -– Part II

 



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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 iswww.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 anythe 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 and December 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, 2007 in the trust’s annual report to unitholders for the year ended December 31, 2007.

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—

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—

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 91%88% of the net profits income received by the trust during 2006,2007, as well as 91%89% of the estimated proved reserves of the net profits interests at December 31, 20062007 (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, 2006.2007. 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, 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 directly increase or decrease 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, 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

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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.

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. In addition, a reduction in depletion tax benefits may reduce the market value of the trust units.

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 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.

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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, generally accepted in theor U.S., or 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 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

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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.1B. Unresolved Staff Comments

As of December 31, 2006,2007, 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.

6



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. In January 2006, XTO Energy announced that it would consider selling the underlying properties. However, XTO Energy advised the trustee in August 2006, that after a full review, it has decided to retain ownership of these underlying property interests at this time.

Hugoton Area

Natural gas was discovered in the Hugoton area in 1922. With an estimated five million productive acres covering parts of Texas, Oklahoma and Kansas, the Hugoton area is one of the largest domestic natural gas producing areas. During 2006,2007, daily sales volumes from the underlying properties in the Hugoton area averaged approximately 23,60021,700 Mcf of gas and 7451 Bbls of oil.

Most of the production from the underlying properties in the Hugoton area is from the Chase formation, at depths of 2,700 to 2,900 feet. XTO Energy has informed the trustee that it plans to develop other formations that underlie the 79,500 net acres held by production by the Chase formation wells, which range from 2,950 to 8,000 feet and 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 successful wells to these formations and plans to continue this development program in 2007. XTO Energy has participated in 3-D seismic shoots covering 30,000 acres of XTO Energy’s net acreage position beneath the Chase formation.2008.

Within this area, XTO Energy successfully drilled three gross (3.0 net) wells and performed 2941 workovers in 2006,2007, of which 2027 were Chase restimulations. XTO Energy has informed the trustee that it plans to drill up to fiveseven wells and perform up to 3025 workovers during 2007.2008.

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

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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 70%71% of its throughput from underlying properties, which, in recent months, has been approximately 16,95016,500 Mcf per day from 264252 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 the monthly pipeline index less $0.01 per MMBtu.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 34,80033,700 Mcf of gas and 799754 Bbls of oil in 2006.2007.

The fields in the Major County area are characterized by oil and gas production from a variety of structural and stratigraphic traps. Productive zones range from 6,500 to 9,400 feet and include the Oswego, Red Fork, Inola, Chester, Manning, Mississippian, Hunton and Arbuckle formations. Within this area, XTO Energy successfully drilled 12 gross (8.0(6.4 net) wells and performed 1231 workovers in 2006.2007. XTO Energy has informed the trustee that it plans to drill up to 12 wells and perform up to 1523 workovers in Major County during 2007.2008.

The fields within Woodward County are characterized primarily by gas production from a variety of structural and stratigraphic traps. Productive zones range from 6,000 to 7,500 feet and include the Cottage Grove, Oswego, Chester and Mississippian formations. Within this area, XTO Energy successfully drilled 1211 gross (10.4(9.2 net) wells and performed fiveseven workovers in 2006.2007. XTO Energy has informed the trustee that it plans to drill up to 11eight wells and perform up to eight workovers in Woodward County during 2007.2008.

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 range from 9,500 to 15,500 feet and include the Hoxbar, Atoka and Morrow formations. Within this area, XTO Energy successfully drilled twofour gross (1.8(3.6 net) wells and performed threeeight workovers in 2006.2007. XTO Energy has informed the trustee that it plans to drill up to fourtwo wells and perform up to sixfour workovers within the Elk City field during 2007.2008.

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 2006,2007, the

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gathering system collected approximately 13,50013,400 Mcf per day from over 400359 wells, approximately 52%55% 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 10,50011,500 Mcf per day from 107117 wells, for an average fee of approximately $0.10 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 Cretaceous-aged Frontier, Baxter and Dakota sandstones at depths ranging from 7,500 to 10,000 feet.

Daily 20062007 sales volumes from the underlying properties in the Fontenelle Field averaged 22,80021,600 Mcf of natural gas and 3832 Bbls of oil. In 2006,2007, XTO Energy successfully drilled eightcompleted six gross (8.0(6.0 net) wells and performed tennine workovers. Of the eight wells drilled in 2006, two wells were completed and six wells were pending completion at December 31. XTO Energy has advised the trustee that it does not planplans to drill up to six wells and perform anyup to eight workovers or drill wells in the Green River Basin during 2007.2008. 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 35 miles to the gas plant, where the gas is processed, then redelivered to XTO Energy and sold to XTO Energy’s marketing subsidiary. The owner of the gas plant and related pipeline charges XTO Energy for operational fuel and processing. In 2006,2007, the fuel charge was 1.2%1.45% of the volumes produced and the processing fee was approximately $0.10 per MMBtu. The marketing subsidiary then sells the residue gas to third parties based upon a spot sales price and pays the net sales proceeds to XTO Energy. The marketing subsidiary does not receive a marketing fee. Effective November 1, 2007, XTO Energy began transporting and selling this gas directly to the markets. The marketing subsidiary is no longer involved. The gas not sold under the above arrangement is sold either under a similar arrangement where the fee is $0.16$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.

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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 operated by XTO Energy and nonoperated wells are operated by other operators.

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, 2006.2007. Undeveloped acreage is not significant.

 

 

Gross

 

Net

 

Hugoton Area

 

216,790

 

199,590

 

Anadarko Basin

 

152,042

 

113,946

 

Green River Basin

 

39,155

 

26,899

 

Total

 

407,987

 

340,435

 


  
 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, 2006:2007:

 

Operated

 

Nonoperated

 

 

 

 

 

      

 

Wells

 

Wells

 

Total

 

 Operated Wells Nonoperated Wells Total

 

Gross

 

Net

 

Gross

 

Net

 

Gross

 

Net

 

 Gross Net Gross Net Gross Net

Gas

 

1,212

 

1,086.6

 

 

276

 

 

64.2

 

1,488

 

1,150.8

 

  1,249   1,112.0   291   67.8   1,540   1,179.8 

Oil

 

45

 

40.1

 

 

9

 

 

2.2

 

54

 

42.3

 

  46   40.6   8   1.7   54   42.3 

Total

 

1,257

 

1,126.7

 

 

285

 

 

66.4

 

1,542

 

1,193.1

 

  1,295   1,152.6   299   69.5   1,594   1,222.1 

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 1310 gross (7.6(5.9 net) wells in process of drilling at December 31, 2006.2007.

 

 

2006

 

2005

 

2004

 

 

 

Gross

 

Net

 

Gross

 

Net

 

Gross

 

Net

 

Completed gas wells

 

 

44

 

 

28.8

 

 

41

 

 

29.2

 

 

25

 

 

19.2

 

Completed oil wells

 

 

3

 

 

0.6

 

 

1

 

 

1.0

 

 

—

 

 

—

 

Non-productive wells

 

 

1

 

 

0.1

 

 

1

 

 

0.5

 

 

4

 

 

1.5

 

Total (a)

 

 

48

 

 

29.5

 

 

43

 

 

30.7

 

 

29

 

 

20.7

 

      
 2007 2006 2005
   Gross Net Gross Net Gross Net
Completed gas wells  51   30.4   44   28.8   41   29.2 
Completed oil wells  —   —   3   0.6   1   1.0 
Non-productive wells  —   —   1   0.1   1   0.5 
Total(a)  51   30.4   48   29.5   43   30.7 

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

(a)Included in totals are 17 gross (4.3 net) wells in 2007, 17 gross (4.3 net) wells in 2006 and 10 gross (2.4 net) wells in 2005, 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, 20062007 were as follows:

   

 

2006

 

2005

 

2004

 

 2007 2006 2005

Production

 

 

 

 

 

 

 

               

Underlying Properties

 

 

 

 

 

 

 

               

Gas—Sales (Mcf)

 

29,628,079

 

29,986,698

 

30,238,663

 

Gas – Sales (Mcf)  28,092,224   29,628,079   29,986,698 

Average per day (Mcf)

 

81,173

 

82,155

 

82,619

 

  76,965   81,173   82,155 

Oil—Sales (Bbls)

 

332,525

 

325,193

 

318,694

 

Oil - Sales (Bbls)  305,594   332,525   325,193 

Average per day (Bbls)

 

911

 

891

 

871

 

  837   911   891 

Net Profits Interests

 

 

 

 

 

 

 

               

Gas—Sales (Mcf)

 

12,871,453

 

15,836,681

 

16,462,378

 

Gas – Sales (Mcf)  11,233,503   12,871,453   15,836,681 

Average per day (Mcf)

 

35,264

 

43,388

 

44,979

 

  30,777   35,264   43,388 

Oil—Sales (Bbls)

 

145,230

 

177,980

 

184,487

 

Oil – Sales (Bbls)  140,805   145,230   177,980 

Average per day (Bbls)

 

398

 

488

 

504

 

  386   398   488 

Average Sales Price

 

 

 

 

 

 

 

               

Gas (per Mcf)

 

$ 6.59

 

$ 6.64

 

$ 4.99

 

 $5.70  $6.59  $6.64 

Oil (per Bbl)

 

$63.73

 

$52.27

 

$38.11

 

 $64.35  $63.73  $52.27 

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, 2007, 2006, 2005 2004 and 2003.2004. 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

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the legal obligation of XTO Energy as the owner of the underlying working interests and will only be 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 $6.72 per Mcf in 2007, $5.60 per Mcf in 2006, $8.72 per Mcf in 2005 and $5.68 per Mcf in 2004 and $5.76 per Mcf in 2003.2004. Year-end oil prices used to determine the standardized measure were based on a West Texas Intermediate crude oil posted price of $92.70 per Bbl in 2007, $57.75 per Bbl in 2006, $57.75 per Bbl in 2005 and $40.25 per Bbl in 2004 and $29.25 per Bbl in 2003.2004.

Proved Reserves

 

Underlying
Properties

 

Net Profits Interests

 

    

(in thousands)

 

Gas

 

Oil

 

   Gas   

 

   Oil   

 

 

(Mcf)

 

(Bbls)

 

(Mcf)

 

(Bbls)

 

 Underlying Properties Net Profits Interests

Balance, December 31, 2003

 

462,328

 

3,769

 

278,783

 

 

2,287

 

 

Extensions, additions and discoveries

 

16,905

 

228

 

9,676

 

 

131

 

 

Revisions of prior estimates

 

(5,061

)

115

 

(17,404

)

 

35

 

 

Production—sales volumes

 

(30,239

)

(319

)

(16,462

)

 

(184

)

 

(in Thousands) Gas (Mcf) Oil (Bbls) Gas (Mcf) Oil (Bbls)

Balance, December 31, 2004

 

443,933

 

3,793

 

254,593

 

 

2,269

 

 

  443,933   3,793   254,593   2,269 

Extensions, additions and discoveries

 

24,806

 

146

 

14,273

 

 

84

 

 

  24,806   146   14,273   84 

Revisions of prior estimates

 

4,292

 

167

 

18,902

 

 

258

 

 

  4,292   167   18,902   258 

Production—sales volumes

 

(29,987

)

(325

)

(15,837

)

 

(178

)

 

Production – sales volumes  (29,987)   (325)   (15,837)   (178) 

Balance, December 31, 2005

 

443,044

 

3,781

 

271,931

 

 

2,433

 

 

  443,044   3,781   271,931   2,433 

Extensions, additions and discoveries

 

17,853

 

203

 

8,938

 

 

102

 

 

  17,853   203   8,938   102 

Revisions of prior estimates

 

(10,817

)

187

 

(37,322

)

 

(195

)

 

  (10,817)   187   (37,322)   (195) 

Production—sales volumes

 

(29,628

)

(333

)

(12,871

)

 

(145

)

 

Production – sales volumes  (29,628)   (333)   (12,871)   (145) 

Balance, December 31, 2006

 

420,452

 

3,838

 

230,676

 

 

2,195

 

  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 

11



Extensions, additions and discoveries in 2004, 2005, 2006 and 20062007 are primarily related to delineation of additional proved undeveloped reserves in the Anadarko Basin. 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

(in thousands)

 

Underlying
Properties

 

Net Profits
Interests

 

 

Gas

 

Oil

 

Gas

 

Oil

 

    

 

(Mcf)

 

(Bbls)

 

(Mcf)

 

(Bbls)

 

 Underlying Properties Net Profits Interests

December 31, 2003

 

396,847

 

3,294

 

241,636

 

2,013

 

(in Thousands) Gas (Mcf) Oil (Bbls) Gas (Mcf) Oil (Bbls)

December 31, 2004

 

381,768

 

3,308

 

220,426

 

1,993

 

  381,768   3,308   220,426   1,993 

December 31, 2005

 

379,527

 

3,361

 

235,470

 

2,180

 

  379,527   3,361   235,470   2,180 

December 31, 2006

 

361,915

 

3,369

 

202,794

 

1,964

 

  361,915   3,369   202,794   1,964 
December 31, 2007  352,732   3,234   198,187   1,896 

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Standardized Measure of Discounted Future Net Cash Flows from Proved Reserves

(in thousands)

 

December 31

 

 

2006

 

2005

 

2004

 

   
 December 31
(in Thousands) 2007 2006 2005

Underlying Properties

 

 

 

 

 

 

 

               

Future cash inflows

 

$

2,574,507

 

$

4,092,655

 

$

2,680,376

 

 $3,061,372  $2,574,507  $4,092,655 

Future costs:

 

 

 

 

 

 

 

               

Production

 

858,794

 

1,109,882

 

856,280

 

  1,014,076   858,794   1,109,882 

Development

 

86,744

 

80,610

 

57,059

 

  78,494   86,744   80,610 

Future net cash flows

 

1,628,969

 

2,902,163

 

1,767,037

 

  1,968,802   1,628,969   2,902,163 

10% discount factor

 

830,281

 

1,511,732

 

895,304

 

  992,874   830,281   1,511,732 

Standardized measure

 

$

798,688

 

$

1,390,431

 

$

871,733

 

 $975,928  $798,688  $1,390,431 

Net Profits Interests

 

 

 

 

 

 

 

               

Future cash inflows

 

$

1,420,936

 

$

2,515,738

 

$

1,539,521

 

 $1,714,576  $1,420,936  $2,515,738 

Future production taxes

 

117,760

 

194,008

 

125,891

 

  139,535   117,760   194,008 

Future net cash flows

 

1,303,176

 

2,321,730

 

1,413,630

 

  1,575,041   1,303,176   2,321,730 

10% discount factor

 

664,225

 

1,209,385

 

716,244

 

  794,299   664,225   1,209,385 

Standardized measure

 

$

638,951

 

$

1,112,345

 

$

697,386

 

 $780,742  $638,951  $1,112,345 


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

(in thousands)

 

 

 

 

 

 

 

 

2006

 

2005

 

2004

 

   
(in Thousands) 2007 2006 2005

Underlying Properties

 

 

 

 

 

 

 

               

Standardized measure, January 1

 

$

1,390,431

 

$

871,733

 

$

925,812

 

 $798,688  $1,390,431  $871,733 

Revisions:

 

 

 

 

 

 

 

               

Prices and costs

 

(578,041

)

566,014

 

(36,596

)

  208,352   (578,041)   566,014 

Quantity estimates

 

5,912

 

5,744

 

(7,115

)

  (18,232)   5,912   5,744 

Accretion of discount

 

119,526

 

75,570

 

79,856

 

  69,710   119,526   75,570 

Future development costs

 

(53,060

)

(56,072

)

(22,304

)

  (28,733)   (53,060)   (56,072) 

Production rates and other

 

(944

)

(92

)

(176

)

  (1,708)   (944)   (92) 

Net revisions

 

(506,607

)

591,164

 

13,665

 

  229,389   (506,607)   591,164 

Extensions, additions and discoveries

 

28,915

 

58,946

 

34,656

 

  35,122   28,915   58,946 

Production

 

(165,751

)

(170,612

)

(123,700

)

  (130,021)   (165,751)   (170,612) 

Development costs

 

51,700

 

39,200

 

21,300

 

  42,750   51,700   39,200 

Net change

 

(591,743

)

518,698

 

(54,079

)

  177,240   (591,743)   518,698 

Standardized measure, December 31

 

$

798,688

 

$

1,390,431

 

$

871,733

 

 $975,928  $798,688  $1,390,431 

Net Profits Interests

 

 

 

 

 

 

 

               

Standardized measure, January 1

 

$

1,112,345

 

$

697,386

 

$

740,650

 

 $638,951  $1,112,345  $697,386 

Extensions, additions and discoveries

 

23,132

 

47,157

 

27,724

 

  28,097   23,132   47,157 

Accretion of discount

 

95,621

 

60,456

 

63,885

 

  55,768   95,621   60,456 

Revisions of prior estimates, changes in price and other (a)

 

(500,906

)

412,475

 

(52,953

)

  128,426   (500,906)   412,475 

Net profits income

 

(91,241

)

(105,129

)

(81,920

)

  (70,500)   (91,241)   (105,129) 

Standardized measure, December 31

 

$

638,951

 

$

1,112,345

 

$

697,386

 

 $780,742  $638,951  $1,112,345 

(a)Revisions were primarily caused by the changes in year-end gas and oil prices and projected costs.12

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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 Income 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 atbased 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 generally 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 2007.2008. 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, styledUnited 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 thequi 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 have beenwas 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

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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 has not been scheduled. The plaintiffs have not statedalleged 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’smanagement's opinion, the amount is not currently expected to be material to the trust’strust'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 2006.2007.

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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, 20062007 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

 

 Year Ended December 31

 

2006

 

2005

 

2004

 

2003

 

2002

 

 2007 2006 2005 2004 2003

Net Profits Income

 

$

91,241,196

 

$

105,129,321

 

$

81,920,014

 

$

80,687,778

 

$

29,934,195

 

 $70,499,584  $91,241,196  $105,129,321  $81,920,014  $80,687,778 

Distributable Income

 

90,910,760

 

104,831,880

 

81,596,920

 

80,373,120

 

29,572,360

 

  69,388,520   90,910,760   104,831,880   81,596,920   80,373,120 

Distributable Income per Unit

 

2.272769

 

2.620797

 

2.039923

 

2.009328

 

0.739309

 

  1.734713   2.272769   2.620797   2.039923   2.009328 

Distributions per Unit

 

2.272769

 

2.620797

 

2.039923

 

2.009328

 

0.739309

 

  1.734713   2.272769   2.620797   2.039923   2.009328 

Total Assets at Year-End

 

165,609,772

 

185,459,610

 

189,499,334

 

198,952,087

 

208,721,083

 

  161,034,033   165,609,772   185,459,610   189,499,334   198,952,087 

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 the three-year period ended December 31, 20062007 in the trust’s annual report to unitholders for the year ended December 31, 20062007 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 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, 2006,2007, other than the December distribution payable to unitholders in January 2007,2008, as reflected in the statement of assets, liabilities and trust corpus.

 

 

Payments due by Period

 

 

 

 

 

Less than

 

 

 

 

 

More than

 

 

 

Total

 

1 Year

 

1-3 Years

 

3-5 Years

 

5 Years

 

Distribution payable to unitholders

 

$

1,813,000

 

$

1,813,000

 

 

$

—

 

 

 

$

—

 

 

 

$

—

 

 


     
 Payments Due by Period
   Total Less than
1 Year		 1 – 3 Years 3 – 5 Years More than
5 Years
Distribution payable to unitholders $5,214,000  $5,214,000  $—  $—  $— 

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, 2006,2007, the monthly overhead charge, based on the number of operated wells, was approximately $716,000$770,000 ($572,800616,000 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. In January 2006, XTO Energy announced that it would consider selling the underlying properties. However, XTO Energy advised the trustee in August 2006, that after a full review, it has decided to retain ownership of these underlying property interests at this time.

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 67 to Financial Statements in the trust’s annual report to unitholders for the year ended December 31, 2006.2007. Total gas sales from the underlying properties to XTO Energy’s wholly owned subsidiaries were $76.6 million for 2007, or 48% of total gas sales, $103.2 million for 2006, or 53% of total gas sales and $107.9 million for 2005, or 54% of total gas sales and $81.7 million for 2004, or 54% 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, 2006.2007.

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

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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.

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, development activities, future development plans, increased density drilling, maintenance projects, development, production and other costs, oil and gas prices, pricing differentials, proved reserves, 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”,“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 aboutAbout 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 the trust’s 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.

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 28, 2007,25, 2008, appearing in the trust’s annual report to unitholders for the year ended December 31, 2006,2007, 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, 2006.2007.

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

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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 inInternal Control—Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on the trustee’s evaluation under the framework inInternal Control—Control — Integrated Framework, the trustee concluded that the trust’s internal control over financial reporting was effective as of December 31, 2006.2007. The trustee’s assessment of the effectiveness of the trust’s internal control over financial reporting as of December 31, 20062007 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, 20062007 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, 20062007 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, and Executive Officers of the Registrant

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 trust. To the trustee’s knowledge, based solely on the information furnished to the trust, the trust 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, 2006, with the exception of one late filing related to one transaction by an immediate family member of Mr. Jack P. Randall, a director of XTO Energy. This transaction has now been reported.2007.

Because the trust has no employees, it does not have a code of ethics. Employees of the trustee, U.S. Trust, Bank of America N.A.,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, 17th Floor, 901 Main Street, Dallas, Texas 75202.

Item 11.Executive Compensation

The trustee received the following annual compensation from 20042005 through 20062007 as specified in the trust indenture:

 

 

 

 

Other Annual

 

Name and Principal Position

 

     Year     

 

     Compensation (1)     

 

Bank of America, N.A., Trustee

 

 

2006

 

 

 

$

47,410

 

 

 

 

 

2005

 

 

 

35,000

 

 

 

 

 

2004

 

 

 

35,000

 

 

  
Name and Principal Position Year Other Annual
Compensation(1)
U.S. Trust, Bank of America Private Wealth Management, Trustee  2007  $43,022 
    2006   47,410 
    2005   35,000 

(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.

(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 22, 2007,January 23, 2008, Bank of America, N.A. owned, in various fiduciary capacities, 99,610124,786 units, with a shared right to vote 17,15626,307 of these units and no right to vote 82,45498,479 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, 20062007 was approximately $716,000$770,000 per month, or $8,592,000$9,240,000 annually (net to the trust of $572,800$616,000 per month or $6,873,600$7,392,000 annually), and is subject to annual adjustment based on an oil and gas industry index as defined in the trust agreement.

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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 20042005 through 20062007 and Item 12(b) for information concerning units owned by the trustee Bank of America, N.A., 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 AccountingAccountant Fees and Services

Fees for services performed by KPMG LLP for the years ended December 31, 20062007 and 2005:2006:

  

 

2006

 

2005

 

 2007 2006

Audit fees

 

$

71,750

 

$

66,000

 

 $71,750  $71,750 

Audit-related fees

 

—

 

—

 

  —   — 

Tax fees

 

—

 

—

 

  —   — 

All other fees

 

—

 

—

 

  —   — 

 

$

71,750

 

$

66,000

 

 $71,750  $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)

(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, 20062007 and 2005

2006
Statements of Distributable Income for the years ended December 31, 2007, 2006 2005 and 2004

2005
Statements of Changes in Trust Corpus for the years ended December 31, 2007, 2006 2005 and 2004

2005
Notes to Financial Statements

2.     Financial Statement Schedules

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)

3.

(a)

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)

(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)

(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)

(d)

Net Overriding Royalty Conveyance (Hugoton Royalty Trust, 80%— – Wyoming) as amended and restated from Cross Timbers Oil Company (predecessor of XTO Energy) to NationsBank, N.A. (now Bank of America, N.A.), as trustee, dated December 1, 1998, heretofore filed as Exhibit 10.1.3 to the trust’s Registration Statement No. 333-68441 on Form S-1 filed with the Securities and Exchange Commission on March 16, 1999, is incorporated herein by reference.

(13)

Hugoton Royalty Trust annual report to unitholders for the year ended December 31, 2006

2007

(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 N.A.,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

HUGOTON ROYALTY TRUST

By:

By BANK OF AMERICA, N.A., TRUSTEE

By

/s/ NANCY G. WILLIS

Nancy G. Willis



Nancy G. Willis
Vice President

XTO ENERGY INC.

Date: February 26, 2008

XTO ENERGY INC.

Date: March 1, 2007

By:

By

/s/ LOUIS G. BALDWIN

Louis G. Baldwin



Louis G. Baldwin
Executive Vice President and


Chief Financial Officer

(The trust has no directors or executive officers.)

23