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, 2009 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 ofIncorporation or Organization)

          

          (I.R.S. EmployerIdentification No.)
 U.S. Trust, Bank of AmericaPrivate Wealth ManagementTrusteeP.O. Box 830650Dallas, 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 onWhich RegisteredUnits 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 o No x 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 whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes o No o Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) 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 oNon-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, 2009 (the last business day of its most recently completed second fiscal quarter), held by non-affiliates of the registrant on that date was approximately $555 million. At February 16, 2010, 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: None
     TABLE OF CONTENTS HUGOTON ROYALTY TRUST   2009 ANNUAL REPORT ON FORM 10-K   TABLE OF CONTENTS   PageGlossary of Terms





1PART IItem 1.Business





2Item 1A.Risk Factors





4Item 1B.Unresolved Staff Comments





9Item 2.Properties





9Item 3.Legal Proceedings





16Item 4.Submission of Matters to a Vote of Security Holders





17PART IIItem 5.Market for Units of the Trust, Related Security Holder Matters and Trust Purchases of Units





18Item 6.Selected Financial Data





18Item 7.Trustees Discussion and Analysis of Financial Condition and Results of Operations





19Item 7A.Quantitative and Qualitative Disclosures about Market Risk





26Item 8.Financial Statements and Supplementary Data





26Item 9.Changes in and Disagreements with Accountants on Accounting and Financial Disclosure





38Item 9A.Controls and Procedures





38Item 9B.Other Information





38PART IIIItem 10.Directors, Executive Officers and Corporate Governance





39Item 11.Executive Compensation





39Item 12.Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters





39Item 13.Certain Relationships and Related Transactions, and Director Independence





39Item 14.Principal Accountant Fees and Services





40PART IVItem 15.Exhibits and Financial Statement Schedules





41
 i    TABLE OF CONTENTS HUGOTON ROYALTY TRUST   GLOSSARY OF TERMS The following are definitions of significant terms used in this Annual Report on Form 10-K:  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 measurementnet 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 conveyancesnet 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
 1    TABLE OF CONTENTS 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. Costs exceeded revenues on properties underlying the Wyoming net profits interests for November 2008 and November and December 2007 and on properties underlying the Kansas net profits interests for October and November 2009. For further information on excess costs, see Trustees Discussion and Analysis of Financial Condition and Results of Operations, under Item 7. 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.
 2    TABLE OF CONTENTS 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 Pricing and Sales Information under Item 2, Properties. On December 13, 2009, XTO Energy entered into a definitive merger agreement with Exxon Mobil Corporation under which XTO Energy would become a wholly owned subsidiary of ExxonMobil. The completion of this merger is subject to certain conditions, including approval of the merger agreement by XTO Energy stockholders and certain government and regulatory approvals. The merger is not expected to have a material effect on trust annual distributable income, financial position or liquidity. The merger is expected to close in the second quarter of 2010. 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 84% of the net profits income received by the trust during 2009, as well as 86% of the estimated proved reserves of the net profits interests at December 31, 2009 (based on estimated future net cash flows using 12-month average oil and gas prices, based on the first-day-of-the-month price for each month in the period), 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.
 3    TABLE OF CONTENTS 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 under Item 8, Financial Statements and Supplementary Data. 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, 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 and the properties underlying the Kansas net profits interests in October and
November 2009), 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
 4    TABLE OF CONTENTS 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. Because trust reserve quantities are determined using an allocation formula, 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, 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, N.A. certificates of deposit which are backed by the good faith and credit of Bank of America, N.A., but are only insured by the Federal Deposit Insurance Corporation up to $250,000. Each unitholder should independently assess the creditworthiness of Bank of America, N.A. For more information about the credit rating of Bank of America, N.A., please refer to its periodic filings with the SEC. The trust does not lend money and has limited ability to borrow money, which the trustee believes
limits the trusts risk from the currently tight 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 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. Information contained in Bank of America N.A.s periodic filings with the SEC is not incorporated by reference into this Annual Report on Form 10-K and should not be considered part of this report or any other filing that the trust makes with the SEC. 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.
 5    TABLE OF CONTENTS 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 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. On December 13, 2009, XTO Energy entered into a definitive merger agreement with Exxon Mobil Corporation under which XTO Energy would become a wholly owned subsidiary of ExxonMobil. The completion of this merger is subject to certain conditions, including approval of the merger agreement by XTO Energy stockholders and certain government and regulatory approvals. The merger is not expected to have a material effect on trust annual distributable income, financial position or liquidity. The merger is expected to close in the second quarter of 2010. 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.
 6    TABLE OF CONTENTS 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 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
 7    TABLE OF CONTENTS 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.
 8    TABLE OF CONTENTS Item 1B. Unresolved Staff Comments As of December 31, 2009, 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, Business. 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. 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. 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, 2009 is approximately 13 years. This index is calculated using total proved reserves and estimated 2010 production for the underlying properties. The projected 2010 production is from proved developed producing reserves as of December 31, 2009. Based on estimated future net cash flows at 12-month average oil and gas prices, based on the
first-day-of-the-month price for each month in the period, the proved reserves of the underlying properties are approximately 86% natural gas and 14% oil. XTO Energy operates approximately 94% of the underlying properties. Because the underlying properties are working interest, 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 of Financial Condition and Results of Operations, under Item 7. Total 2009 development costs deducted for the underlying properties were $21 million, a decrease of 54% from the prior year. XTO Energy has informed the trustee that total 2010 budgeted development costs for the underlying properties are between $10 million and $15
million. Significant Properties Hugoton Area Natural gas was discovered in the Hugoton area in 1922. With an estimated five million productive acres covering parts of Texas, Oklahoma and Kansas, the Hugoton area is one of the largest domestic natural gas producing areas. During 2009, daily sales volumes from the underlying properties in the Hugoton area averaged approximately 19,200 Mcf of gas and 50 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 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 2010. Within this area, XTO Energy drilled 3 gross (3.0 net) wells but did not perform any workovers in 2009. XTO Energy has informed the trustee that it plans to drill up to two wells and will perform up to 20 workovers during 2010. 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,
 9    TABLE OF CONTENTS 

          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 62% of its throughput from underlying properties, which, in recent months, has been approximately 14,000 Mcf per day from 254 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 third party 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 34,100 Mcf of gas and 618 Bbls of oil in 2009. 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 1 gross (1.0 net) wells but did not perform any workovers in 2009. XTO Energy has informed the trustee that it does not plan to drill any new wells but will perform up to 12 workovers in Major County during 2010. The fields within Woodward County are characterized primarily by gas production from a variety of structural and stratigraphic traps. Productive zones include the Cottage Grove, Oswego, Chester and Mississippian formations. Within this area, XTO Energy did not drill any wells or perform any workovers in 2009. XTO Energy has informed the trustee that it does not plan to drill any new wells but will perform up to 6 workovers in Woodward County during 2010. 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 but did not perform any workovers in 2009. XTO Energy has informed the trustee that it plans to drill up to three wells and perform up to 10 workovers within the Elk City field during 2010. 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
 10    TABLE OF CONTENTS with an interstate pipeline. The gathering subsidiary sells the residue gas to the marketing subsidiary of XTO Energy based upon a weighted average 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 2009, the gathering system collected approximately 12,000 Mcf per day from 365 wells, approximately 57% 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 12,000 Mcf per day from 184 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 2009 sales volumes from the underlying properties in the Fontenelle Field averaged 19,700 Mcf of natural gas and 46 Bbls of oil. In 2009, XTO Energy did not drill any wells or perform any workovers. XTO Energy has advised the trustee that it does not plan to drill any new wells but will perform up to 4 workovers in the Green River Basin during 2010. 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 2009, the fuel charge was 1.89% 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 spot sales price. The gas not sold under the above arrangement is sold either under a similar arrangement where the fee is approximately $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, Drilling 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.
 11    TABLE OF CONTENTS 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, 2009. Undeveloped acreage is not significant.  Gross

          

          NetHugoton Area

          

          

          212,886

          

          

          

          198,010Anadarko Basin

          

          

          180,333

          

          

          

          134,500Green River Basin

          

          

          37,912

          

          

          

          28,375Total

          

          

          431,131

          

          

          

          360,885
 The following is a summary of the producing wells on the underlying properties as of December 31, 2009:  Operated Wells

          

          Nonoperated Wells

          

          TotalGross

          

          Net

          

          Gross

          

          Net

          

          Gross

          

          NetGas

          

          

          1,267.0

          

          

          

          1,125.0

          

          

          

          306.0

          

          

          

          70.2

          

          

          

          1,573.0

          

          

          

          1,195.2Oil

          

          

          43.0

          

          

          

          38.2

          

          

          

          8.0

          

          

          

          1.4

          

          

          

          51.0

          

          

          

          39.6Total

          

          

          1,310.0

          

          

          

          1,163.2

          

          

          

          314.0

          

          

          

          71.6

          

          

          

          1,624.0

          

          

          

          1,234.8
 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 2 gross (1.0 net) wells in process of drilling at December 31, 2009.  2009

          

          2008

          

          2007Gross

          

          Net

          

          Gross

          

          Net

          

          Gross

          

          NetCompleted gas wells

          

          

          9

          

          

          

          5.1

          

          

          

          54

          

          

          

          35.0

          

          

          

          51

          

          

          

          30.4Completed oil wells

          

          

          1

          

          

          

          1.0

          

          

          

          1

          

          

          

          0.1

          

          

          

          

          

          

          

          Non-productive wells

          

          

          

          

          

          

          

          

          

          

          

          

          

          

          

          

          

          

          

          

          

          

          Total(a)

          

          

          10

          

          

          

          6.1

          

          

          

          55

          

          

          

          35.1

          

          

          

          51

          

          

          

          30.4
  (a)

          Included in totals are 5 gross (1.2 net) wells in 2009, 14 gross (2.6 net) wells in 2008 and 17 gross (4.3 net) wells in 2007, drilled on nonoperated interests. 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, 2009:  Underlying Properties

          

          Net Profits InterestsProved Reserves(a)

          

          Proved Reserves(a)(b)

          

          Future Net Cash Flows fromProved Reserves(a)(c)Gas (Mcf)

          

          Oil (Bbls)

          

          Gas (Mcf)

          

          Oil (Bbls)

          

          Undiscounted

          

          Discounted(in Thousands)Oklahoma

          

          

          212,999

          

          

          

          2,511

          

          

          

          83,040

          

          

          

          972

          

          

          $

          313,488

          

          

          $

          162,865Wyoming

          

          

          85,663

          

          

          

          102

          

          

          

          23,805

          

          

          

          29

          

          

          

          63,585

          

          

          

          34,226Kansas

          

          

          24,583

          

          

          

          392

          

          

          

          10,208

          

          

          

          123

          

          

          

          39,264

          

          

          

          22,932TOTAL

          

          

          323,245

          

          

          

          3,005

          

          

          

          117,053

          

          

          

          1,124

          

          

          $

          416,337

          

          

          $

          220,023
  (a)

          Based on 12-month average oil price of $57.17 per Bbl and $3.28 per Mcf for gas, based on the first-day-of-the-month price for each month in the period. Discounted estimated future net cash flows from proved reserves decreased 47% from year-end 2008 to 2009, primarily because of a 27% decrease in natural gas prices partially offset by a 36% increase in oil prices.
 12    TABLE OF CONTENTS (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. Future net cash flows are discounted at an annual rate of 10%. Our proved reserves consists of the following:  Underlying Properties

          

          Net Profits InterestsProved Reserves

          

          Proved ReservesGas (Mcf)

          

          Oil (Bbls)

          

          Gas (Mcf)

          

          Oil (Bbls)(in Thousands)Proved developed reserves

          

          

          283,864

          

          

          

          2,560

          

          

          

          110,050

          

          

          

          1,056Proved undeveloped reserves

          

          

          39,381

          

          

          

          445

          

          

          

          7,003

          

          

          

          68Total proved reserves

          

          

          323,245

          

          

          

          3,005

          

          

          

          117,053

          

          

          

          1,124
 Approximately 88% of the underlying proved reserves are proved developed reserves. The process of estimating oil and gas reserves is complex and requires significant judgment as discussed in Item 1A, Risk Factors, and is performed by XTO Energy. As a result, XTO Energy has developed internal policies and controls for estimating and recording reserves. XTO Energys policies regarding booking reserves require proved reserves to be in compliance with the SEC definitions and guidance. XTO Energys policies assign responsibilities for compliance in reserves bookings to its reserve engineering group and require that reserve estimates be made by qualified reserves estimators, as defined by the Society of Petroleum
Engineers standards. All qualified reserves estimators are required to receive education covering the fundamentals of SEC proved reserves assignments. The XTO Energy reserve engineering group reviews reserve estimates with our third-party petroleum consultants, Miller and Lents, Ltd., independent petroleum engineers. Miller and Lents, Ltd. estimated oil and gas reserves attributable to the underlying properties as of December 31, 2009, 2008, 2007 and 2006. Miller and Lents primary technical person responsible for calculating the trusts reserves has more than 30 years of experience as a reserve engineer. 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.
 13    TABLE OF CONTENTS 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, 2009 were as follows:  2009

          

          2008

          

          2007ProductionUnderlying PropertiesGas  Sales (Mcf)

          

          

          26,641,595

          

          

          

          28,176,094

          

          

          

          28,092,224Average per day (Mcf)

          

          

          72,991

          

          

          

          76,984

          

          

          

          76,965Oil  Sales (Bbls)

          

          

          260,499

          

          

          

          341,754

          

          

          

          305,594Average per day (Bbls)

          

          

          714

          

          

          

          934

          

          

          

          837Net Profits InterestsGas  Sales (Mcf)

          

          

          8,326,148

          

          

          

          13,134,564

          

          

          

          11,233,503Average per day (Mcf)

          

          

          22,811

          

          

          

          35,887

          

          

          

          30,777Oil  Sales (Bbls)

          

          

          90,552

          

          

          

          169,915

          

          

          

          140,805Average per day (Bbls)

          

          

          248

          

          

          

          464

          

          

          

          386Average Sales PriceGas (per Mcf)

          

          $

          3.38

          

          

          $

          7.75

          

          

          $

          5.70Oil (per Bbl)

          

          $

          54.10

          

          

          $

          104.62

          

          

          $

          64.35
 Pricing and Sales Information A subsidiary of XTO Energy purchases most of XTO Energys natural gas production based on a weighted average sales price, then sells the gas to third parties. 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 2010. 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.  Regulation Natural Gas Regulation The interstate transportation and sale for resale of natural gas is subject to federal regulation, including transportation and storage rates charged, 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. 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 by Congress or the various state legislatures, and what
effect, if any, such proposals might have on the operations of the underlying properties. 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 regulations to implement the Energy Policy Act.
 14    TABLE OF CONTENTS Federal Regulation of Oil Sales of crude oil, condensate and natural gas liquids are not currently regulated and are made at market prices. The net price received from the sale of these products is affected by market transportation costs. Under rules adopted by FERC effective January 1995, interstate oil pipelines can change rates based on an inflation index, though other rate mechanisms may be used in specific circumstances. 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, sales or
transportation transactions. 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. There is an increased focus by local, national and international regulatory bodies on greenhouse gas (GHG) emissions and climate change. Various regulatory bodies have announced their intent to regulate GHG emissions. As these regulations are under development, XTO Energy is unable to predict the total impact of the potential regulations upon the operators of the underlying properties, and it is possible that operators of the underlying properties could face increases in operating costs in order to comply with GHG emissions legislation, which costs could reduce net proceeds payable to the trust and trust distributions. 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.
 15    TABLE OF CONTENTS 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. 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. Grynberg 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. Grynberg 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 filed an appeal of this decision to
the United States Tenth Circuit Court of Appeals. In March 2009, the Tenth Circuit affirmed the trial courts dismissal of the case and the U.S. Supreme Court has denied Grynbergs application for appeal. XTO Energy has entered into an agreement with the plaintiff whereby XTO Energy and the plaintiff dismissed all claims against each other. The court granted the dismissal of the claims on November 3, 2009, effectively ending this case. 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 certain royalty owners of natural gas wells in Oklahoma and Kansas. 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. At the class certification hearing, the plaintiffs sought to certify a class of royalty owners whose wells were connected to a processing plant owned by a subsidiary of XTO Energy in the Hugoton Field, with two sub-classes consisting of owners in Oklahoma and Kansas. In March 2009, the District Court granted the motion to certify the class. The plaintiffs filed a motion for summary judgment for only the two named plaintiffs. The court granted the motion in the amount of $12,779. A motion for summary judgment related to the remainder of the class is pending. Trial on the merits is scheduled for 2010. 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. The case
is set for trial in 2010. 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. It could, however, result in costs exceeding revenues on the properties underlying the Oklahoma and Kansas net profit interests for one or more monthly distributions, depending on the size of the judgment or settlement, if any, and the net proceeds being paid
at that time.
 16    TABLE OF CONTENTS 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 plaintiffs claims overlap the claims made by the plaintiffs in the Beer case as to certain properties. XTO
Energy has answered, denying all claims, and has filed motions to dismiss a portion of the claims. The federal court recently granted XTO Energys motion for summary judgment concerning prior settled class actions that overlap plaintiffs proposed class action. The court also granted XTO Energys motion to dismiss those portions of plaintiffs class that are currently being prosecuted in the Beer class action discussed above. 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. It could, however, result in costs exceeding revenues on the properties underlying the Oklahoma and Kansas net profit interests for one or more monthly distributions, depending on the size of the judgment or settlement, if any, and the net proceeds being paid at that time. 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 2009.
 17    TABLE OF CONTENTS PART II Item 5. Market for Units of the Trust, Related Security Holder Matters and Trust Purchases of Units 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 2009 and 2008:  Sales Price

          

          Distributionsper UnitQuarter

          

          High

          

          Low2009First

          

          $

          18.08

          

          

          $

          7.29

          

          

          $

          0.136634Second

          

          

          15.02

          

          

          

          9.26

          

          

          

          0.106593Third

          

          

          19.05

          

          

          

          11.96

          

          

          

          0.209290Fourth

          

          

          18.40

          

          

          

          15.45

          

          

          

          0.280139$

          0.732656
  2008First

          

          $

          29.85

          

          

          $

          22.52

          

          

          $

          0.544229Second

          

          

          37.86

          

          

          

          27.14

          

          

          

          0.838873Third

          

          

          37.65

          

          

          

          24.50

          

          

          

          1.092216Fourth

          

          

          27.29

          

          

          

          14.00

          

          

          

          0.437042$

          2.912360
 At December 31, 2009, there were 40,000,000 units outstanding and approximately 994 unitholders of record; 39,277,902 of these units were held by depository institutions. 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 312009

          

          2008

          

          2007

          

          2006

          

          2005Net Profits Income

          

          $

          30,180,880

          

          

          $

          117,268,069

          

          

          $

          70,499,584

          

          

          $

          91,241,196

          

          

          $

          105,129,321Distributable Income

          

          

          29,306,240

          

          

          

          116,494,400

          

          

          

          69,388,520

          

          

          

          90,910,760

          

          

          

          104,831,880Distributable Income per Unit

          

          

          0.732656

          

          

          

          2.912360

          

          

          

          1.734713

          

          

          

          2.272769

          

          

          

          2.620797Distributions per Unit

          

          

          0.732656

          

          

          

          2.912360

          

          

          

          1.734713

          

          

          

          2.272769

          

          

          

          2.620797Total Assets at Year-End

          

          

          144,162,380

          

          

          

          147,867,855

          

          

          

          161,034,033

          

          

          

          165,609,772

          

          

          

          185,459,610
 18    TABLE OF CONTENTS Item 7. Trustees Discussion and Analysis of Financial Condition and Results of Operations 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 EndedDecember 31(a)2009

          

          2008

          

          2007

          

          2009

          

          2008Sales VolumesGas (Mcf)(b)Underlying properties

          

          

          26,641,595

          

          

          

          28,176,094

          

          

          

          28,092,224

          

          

          

          6,536,638

          

          

          

          6,808,017Average per day

          

          

          72,991

          

          

          

          76,984

          

          

          

          76,965

          

          

          

          71,050

          

          

          

          74,000Net profits interests

          

          

          8,326,148

          

          

          

          13,134,564

          

          

          

          11,233,503

          

          

          

          3,053,845

          

          

          

          2,218,747Oil (Bbls)(b)Underlying properties

          

          

          260,499

          

          

          

          341,754

          

          

          

          305,594

          

          

          

          54,739

          

          

          

          77,975Average per day

          

          

          714

          

          

          

          934

          

          

          

          837

          

          

          

          595

          

          

          

          848Net profits interests

          

          

          90,552

          

          

          

          169,915

          

          

          

          140,805

          

          

          

          26,195

          

          

          

          29,676Average Sales PricesGas (per Mcf)

          

          $

          3.38

          

          

          $

          7.75

          

          

          $

          5.70

          

          

          $

          3.45

          

          

          $

          6.03Oil (per Bbl)

          

          $

          54.10

          

          

          $

          104.62

          

          

          $

          64.35

          

          

          $

          78.90

          

          

          $

          91.81RevenuesGas sales

          

          $

          90,049,682

          

          

          $

          218,253,910

          

          

          $

          160,104,931

          

          

          $

          22,564,668

          

          

          $

          41,058,215Oil sales

          

          

          14,092,634

          

          

          

          35,754,556

          

          

          

          19,666,471

          

          

          

          4,318,749

          

          

          

          7,158,846Total Revenues

          

          

          104,142,316

          

          

          

          254,008,466

          

          

          

          179,771,402

          

          

          

          26,883,417

          

          

          

          48,217,061CostsTaxes, transportation and other

          

          

          13,849,086

          

          

          

          23,271,226

          

          

          

          18,429,983

          

          

          

          3,664,113

          

          

          

          4,643,403Production expense

          

          

          21,038,815

          

          

          

          27,454,543

          

          

          

          22,268,104

          

          

          

          4,925,553

          

          

          

          7,028,920Development costs(c)

          

          

          21,000,000

          

          

          

          46,000,000

          

          

          

          42,750,000

          

          

          

          1,500,000

          

          

          

          12,000,000Overhead

          

          

          10,628,875

          

          

          

          9,830,861

          

          

          

          9,052,303

          

          

          

          2,728,359

          

          

          

          2,552,099Excess costs(d)

          

          

          (100,560)

          

          

          

          866,750

          

          

          

          (853,468

          )

          

          

          (100,560)

          

          

          

          3,192Total Costs

          

          

          66,416,216

          

          

          

          107,423,380

          

          

          

          91,646,922

          

          

          

          12,717,465

          

          

          

          26,227,614Net Proceeds

          

          

          37,726,100

          

          

          

          146,585,086

          

          

          

          88,124,480

          

          

          

          14,165,952

          

          

          

          21,989,447Net Profits Percentage

          

          

          80%

          

          

          

          80

          %

          

          

          80

          %

          

          

          80%

          

          

          

          80

          %Net Profits Income

          

          $

          30,180,880

          

          

          $

          117,268,069

          

          

          $

          70,499,584

          

          

          $

          11,332,762

          

          

          $

          17,591,558
  (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 under Item 8, Financial Statements and Supplementary Data. (d)

          See Note 4 to Financial Statements under Item 8, Financial Statements and Supplementary Data.
 19    TABLE OF CONTENTS Results of Operations Years Ended December 31, 2009, 2008 and 2007 Net profits income for 2009 was $30,180,880, as compared with $117,268,069 for 2008 and $70,499,584 for 2007. The 74% decrease in net profits income from 2008 to 2009 is primarily the result of lower oil and gas prices and decreased oil and gas production, partially offset by lower development costs, lower taxes, transportation and other costs and decreased production expense. The 66% increase in net profits income from 2007 to 2008 was 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.
Approximately 84% in 2009, 85% in 2008 and 88% in 2007 of net profits income was derived from natural gas sales. Trust administration expense was $875,105 in 2009 as compared to $864,872 in 2008 and $1,246,189 in 2007. 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. Interest income was $465 in 2009, $91,203 in 2008 and $135,125 in 2007. Changes in interest income are attributable to fluctuations in net profits income and interest rates. Distributable income was $29,306,240 or $0.732656 per unit in 2009, $116,494,400 or $2.912360 per unit in 2008 and $69,388,520 or $1.734713 per unit in 2007. 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 2008 to 2009, underlying gas sales volumes decreased 5% due to natural production decline, partially offset by the timing of cash receipts and increased production from new wells and workovers. Underlying oil sales volumes decreased 24% from 2008 to 2009 primarily because of the timing of cash receipts and natural production decline, partially offset by increased production from new wells and workovers. 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 adjustments, partially offset by natural production decline. Prices Gas.  The 2009 average gas price was $3.38 per Mcf, a 56% decrease from the 2008 average gas price of $7.75 Mcf, which was 36% higher than the 2007 average gas price of $5.70 per Mcf. Natural gas prices are affected by the level of North American production, weather, crude oil prices, the U.S. economy, storage levels and import levels of liquefied natural gas. In the first part of 2008, prices for natural gas increased significantly reaching as high as $13.00 per MMBtu in July 2008. Since that date, prices have dropped due to higher than average natural gas in storage caused by shale gas development and declining demand due to the
U.S. recession. 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 pipeline
maintenance have led to a partial rebound of Rocky Mountain gas prices. At February 16, 2010, the average futures price for Wyoming gas for the following six months is expected to be approximately 6%
 20    TABLE OF CONTENTS lower than the NYMEX price. Wyoming gas production was approximately 27% of total trust gas production for the year ended December 31, 2009. The trusts average realized gas price was $3.38 per Mcf, 23% lower than the average NYMEX price of $4.37 in 2009; $7.75 per Mcf, 15% lower than the average NYMEX price of $9.13 in 2008; and $5.70 per Mcf, or 18%, lower than the average NYMEX price of $6.94 in 2007. The average NYMEX price for November 2009 through January 2010 was $4.86 per MMBtu. At February 17, 2010, the average NYMEX gas price for the following 12 months was $5.77 per MMBtu. Oil.  The average oil price for 2009 was $54.10 per Bbl, 48% lower than the average oil price for 2008 of $104.62 per Bbl, which was 63% higher than the average oil price for 2007 of $64.35 per Bbl. In the first part of 2008, prices for oil increased significantly reaching a record high above $147.00 per Bbl in July 2008. However, lower demand as a result of the global economic situation caused oil prices to decline below $40.00 per Bbl last winter. Signs of possible economic improvement have resulted in higher recent oil prices. Oil prices are expected to remain volatile. The average NYMEX price for November 2009 through January
2010 was $76.81 per Bbl. At February 17, 2010, the average NYMEX oil price for the following 12 months was $79.48 per Bbl. Recent trust oil prices have averaged approximately 5% 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 decreased 40% from 2008 to 2009 primarily because of decreased production taxes related to lower revenues, partially offset by increased other deductions as a percentage of oil and gas 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. Production.  Production expense decreased 23% from 2008 to 2009 primarily because of decreased repairs and maintenance, location and power and fuel costs. 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. Development.  Development costs deducted were $21.0 million in 2009, $46.0 million in 2008 and $42.8 million in 2007. In 2009, actual development costs were $12.8 million. At December 31, 2009, cumulative budgeted costs exceeded cumulative actual costs by approximately $0.9 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 through the March 2009 distribution. As a result of decreased development activity and revisions to the 2009 development budget, the development cost deduction was decreased to $2.0 million beginning with the April 2009 distribution, to $1.0 million beginning with the June 2009 distribution and to $500,000 beginning with the September 2009 distribution and was maintained at the level for the remainder of 2009. The monthly deduction is based in the current level of development expenditures, budgeted future development costs and the cumulative actual costs under (over) previous deductions. XTO Energy has advised the trustee that this monthly deduction
will continue to be evaluated and revised as necessary.
 21    TABLE OF CONTENTS 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. Excess costs.  Costs exceeded revenues by $513,475 ($410,780 to the trust) on properties underlying the Kansas net profits interests in October and November 2009. Lower gas prices due to reduced demand as a result of the U.S. recession and excess supply caused costs to exceed revenues on properties underlying the Kansas net profits interests. However, these excess costs did not reduce net proceeds from the remaining conveyances. XTO Energy advised the trustee that increased gas prices led to the partial recovery of excess costs of $410,957 ($328,766 net to the trust), plus accrued interest of $1,958 ($1,566 net to the trust) in
December 2009 and the full recovery of excess costs, plus accrued interest in January 2010. 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 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. 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), were fully recovered by February 2008. Fourth Quarter 2009 and 2008 During fourth quarter 2009 the trust received net profits income totaling $11,332,762 compared with fourth quarter 2008 net profits income of $17,591,558. This 36% decrease in net profits income was primarily due to lower oil and gas prices and decreased oil and gas production, partially offset by lower development costs and decreased production expense. Administration expense was $127,308 and interest income was $106, resulting in fourth quarter 2009 distributable income of $11,205,560 or $0.280139 per unit. Distributable income for fourth quarter 2008 was $17,481,680 or $0.437042 per unit. Distributions to unitholders for the quarter ended December 31, 2009 were:   Record Date

          

          Payment Date

          

          Per UnitOctober 30, 2009

          

          

          November 16, 2009

          

          

          $

          0.096543November 30, 2009

          

          

          December 14, 2009

          

          

          

          0.076476December 31, 2009

          

          

          January 15, 2010

          

          

          

          0.107120$

          0.280139
 Volumes Fourth quarter underlying gas sales volumes decreased 4% and underlying oil sales volumes decreased 30% from 2008 to 2009. Gas sales volumes decreased primarily because of natural production decline, partially offset by increased production from new wells and workovers and the timing of cash receipts. Oil sales volumes decreased primarily because of the timing of cash receipts, natural production decline and prior period adjustments, partially offset by increased production from new wells and workovers.
 22    TABLE OF CONTENTS Prices The average fourth quarter 2009 gas price was $3.45 per Mcf, or 43% lower than the fourth quarter 2008 average price of $6.03 per Mcf. The average fourth quarter 2009 oil price was $78.90 per Bbl, or 14% lower than the fourth quarter 2008 average price of $91.81 per Bbl. For further information about product prices, see Years Ended December 31, 2009, 2008 and 2007  Prices above. Costs Taxes, transportation and other.  Taxes, transportation and other generally fluctuates with changes in total revenues. Taxes, transportation and other decreased 21% from 2008 to 2009 primarily due to the 44% decrease in total revenues over the same period, partially offset by increased other deductions as a percentage of oil and gas revenues. Production.  Fourth quarter production expense decreased 30% from 2008 to 2009 primarily because of decreased repairs and maintenance, compressor rentals, location and fuel costs, partially offset by mechanical and marketing rebates received in 2008. Development.  Development costs, which were deducted based on budgeted development costs, decreased 88% from fourth quarter 2008 to 2009 primarily because of decreased development activity. Overhead.  Overhead increased 7% from fourth quarter 2008 to 2009 primarily because of the annual rate adjustment based on an oil and gas industry index. Excess costs.  Costs exceeded revenues by $513,475 ($410,780 to the trust) on properties underlying the Kansas net profits interests in October and November 2009. Lower gas prices due to reduced demand as a result of the U.S. recession and excess supply caused costs to exceed revenues on properties underlying the Kansas net profits interests. However, these excess costs did not reduce net proceeds from the remaining conveyances. XTO Energy advised the trustee that increased gas prices led to the partial recovery of excess costs of $410,957 ($328,766 net to the trust), plus accrued interest of $1,958 ($1,566 net to the trust) in
December 2009 and the full recovery of excess costs, plus accrued interest in January 2010. 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 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. For further information about costs, see Years Ended December 31, 2009, 2008 and 2007  Costs above. 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. Greenhouse Gas Emissions and Climate Change Regulation There is an increased focus by local, national and international regulatory bodies on greenhouse gas (GHG) emissions and climate change. Various regulatory bodies have announced their intent to regulate GHG emissions. As these regulations are under development, XTO Energy is unable to predict the total
 23    TABLE OF CONTENTS impact of the potential regulations upon the operators of the underlying properties, and it is possible that the operators of the underlying properties could face increases in operating costs in order to comply with GHG emissions legislation, which costs could reduce net proceeds payable to the trust and trust distributions. 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, 2009, other than the December distribution payable to unitholders in January 2010, as reflected in the statement of assets, liabilities and trust corpus.  Payments due by PeriodTotal

          

          Less than1 Year

          

          1  3 Years

          

          3  5 Years

          

          More than5 YearsDistribution payable to unitholders

          

          $

          4,284,800

          

          

          $

          4,284,800

          

          

          $

          

          

          

          $

          

          

          

          $

          
 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, 2009, the monthly overhead charge, based on the number of operated wells, was approximately $911,000 ($728,800 the trust) and is subject to annual adjustment based on an oil and gas industry index. 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 under Item 8, Financial Statements and Supplementary Data. Total gas sales from the underlying properties to XTO Energys wholly owned subsidiaries were $42.2 million for 2009, or 47% of total gas sales,
$103.3 million for 2008, or 47% of total gas sales and $76.6 million for 2007, or 48% of total gas sales. On December 13, 2009, XTO Energy entered into a definitive merger agreement with Exxon Mobil Corporation under which XTO Energy would become a wholly owned subsidiary of ExxonMobil. The completion of this merger is subject to certain conditions, including approval of the merger agreement by XTO Energy stockholders and certain government and regulatory approvals. The merger is not expected to have a material effect on trust annual distributable income, financial position or liquidity. The merger is expected to close in the second quarter of 2010. 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.
 24    TABLE OF CONTENTS 

          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 under Item 8, Financial Statements and Supplementary Data. 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 using12-month average prices, based on the first-day-of-the-month price for each month in the period, 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 Note 9 to Financial Statements under Item 8, Financial Statements and Supplementary Data, is prepared using assumptions required by the Financial Accounting Standards Board and the Securities and Exchange Commission. Such assumptions include using 12-month average oil and gas prices, based on the first-day-of-the-month price for each month in the period for 2009, and year end costs for estimated future development and production expenditures. Prior to 2009, standardized measure was calculated using year end oil and gas prices and costs.
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, 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
 25    TABLE OF CONTENTS 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, Risk Factors. 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. Item 8. Financial Statements and Supplementary Data  PageStatements of Assets, Liabilities and Trust Corpus





27Statements of Distributable Income





27Statements of Changes in Trust Corpus





27Notes to Financial Statements





28Report of Independent Registered Public Accounting Firm





37
 All financial statement schedules are omitted as they are inapplicable or the required information has been included in the consolidated financial statements or notes thereto.
 26    TABLE OF CONTENTS HUGOTON ROYALTY TRUST STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS  December 312009

          

          2008AssetsCash and short-term investments

          

          $

          4,284,800

          

          

          $

          1,145,840Net profits interests in oil and gas properties  net (Notes 1 and 2)

          

          

          139,877,580

          

          

          

          146,722,015$

          144,162,380

          

          

          $

          147,867,855Liabilities and Trust CorpusDistribution payable to unitholders

          

          $

          4,284,800

          

          

          $

          1,145,840Trust corpus (40,000,000 units of beneficial interest authorized and outstanding)

          

          

          139,877,580

          

          

          

          146,722,015$

          144,162,380

          

          

          $

          147,867,855
 STATEMENTS OF DISTRIBUTABLE INCOME  Year Ended December 312009

          

          2008

          

          2007Net profits income

          

          $

          30,180,880

          

          

          $

          117,268,069

          

          

          $

          70,499,584Interest income

          

          

          465

          

          

          

          91,203

          

          

          

          135,125Total income

          

          

          30,181,345

          

          

          

          117,359,272

          

          

          

          70,634,709Administration expense

          

          

          875,105

          

          

          

          864,872

          

          

          

          1,246,189Distributable income

          

          $

          29,306,240

          

          

          $

          116,494,400

          

          

          $

          69,388,520Distributable income per unit (40,000,000 units)

          

          $

          0.732656

          

          

          $

          2.912360

          

          

          $

          1.734713
 STATEMENTS OF CHANGES IN TRUST CORPUS  Year Ended December 312009

          

          2008

          

          2007Trust corpus, beginning of year

          

          $

          146,722,015

          

          

          $

          155,820,033

          

          

          $

          163,796,772Amortization of net profits interests

          

          

          (6,844,435)

          

          

          

          (9,098,018

          )

          

          

          (7,976,739

          )Distributable income

          

          

          29,306,240

          

          

          

          116,494,400

          

          

          

          69,388,520Distributions declared

          

          

          (29,306,240)

          

          

          

          (116,494,400

          )

          

          

          (69,388,520

          )Trust corpus, end of year

          

          $

          139,877,580

          

          

          $

          146,722,015

          

          

          $

          155,820,033
 See Accompanying Notes to Financial Statements.
 27    TABLE OF CONTENTS 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: 

          Net profits income is recognized in the month received rather than accrued in the month of production.
 28    TABLE OF CONTENTS HUGOTON ROYALTY TRUST   NOTES TO FINANCIAL STATEMENTS 2. Basis of Accounting   (continued) 

          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 May 2009, the trust adopted the authoritative guidance of accounting for and disclosures of events that occur after the balance sheet date but before financial statements are issued or are available to be issued. We have evaluated subsequent events through February 22, 2010. 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 $107,189,371 as of December 31, 2009 and $100,344,936 as of December 31, 2008. 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). 4. Excess Costs Costs exceeded revenues by $513,475 ($410,780 to the trust) on properties underlying the Kansas net profits interests in October and November 2009. Lower gas prices due to reduced demand as a result of the U.S. recession and excess supply caused costs to exceed revenues on properties underlying the Kansas net profits interests. However, these excess costs did not reduce net proceeds from the remaining conveyances. XTO Energy advised the trustee that increased gas prices led to the partial recovery of excess costs of $410,957 ($328,766 net to the trust), plus accrued interest of $1,958 ($1,566 net to the trust) in December 2009 and the full recovery
of excess costs, plus accrued interest in January 2010. 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
 29    TABLE OF CONTENTS HUGOTON ROYALTY TRUST   NOTES TO FINANCIAL STATEMENTS 4. Excess Costs   (continued) not reduce net proceeds from the remaining conveyances. XTO Energy 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 regional 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 interests, 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), were 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 312009

          

          2008

          

          2007Cumulative actual costs (over) under the amount deducted  beginning of period

          

          $

          (7,314,084)

          

          

          $

          (675,754

          )

          

          $

          (3,410,174

          )Actual costs

          

          

          (12,776,439)

          

          

          

          (52,638,330

          )

          

          

          (40,015,580

          )Budgeted costs deducted

          

          

          21,000,000

          

          

          

          46,000,000

          

          

          

          42,750,000Cumulative actual costs under (over) the amount deducted  end of period

          

          $

          909,477

          

          

          $

          (7,314,084

          )

          

          $

          (675,754

          )
 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 through the March 2009 distribution. As a result of decreased development activity and revisions to the 2009 development budget, the development cost deduction was decreased to $2.0 million beginning with the April 2009 distribution, to $1.0 million beginning with the June 2009 distribution and to $500,000 beginning with the September 2009 distribution and was maintained at the level for the remainder of 2009. The monthly deduction is based in the current level of development expenditures, budgeted future development costs and the cumulative actual costs under (over) previous deductions. 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.
 30    TABLE OF CONTENTS 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, 2009, the overhead charge was approximately $911,000 ($728,800 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. 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 $42.2 million for 2009, or 47% of total gas sales, $103.3 million for 2008, or 47% of total gas sales and $76.6 million for 2007, or 48% of total gas sales. On December 13, 2009, XTO Energy entered into a definitive merger agreement with Exxon Mobil Corporation under which XTO Energy would become a wholly owned subsidiary of ExxonMobil. The completion of this merger is subject to certain conditions, including approval of the merger agreement by XTO Energy stockholders and certain government and regulatory approvals. The merger is not expected to have a material effect on trust annual distributable income, financial position or liquidity. The merger is expected to close in the second quarter of 2010. 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. Grynberg 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. Grynberg 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 filed an appeal of this decision to
the United States Tenth Circuit Court of Appeals. In March 2009,
 31    TABLE OF CONTENTS HUGOTON ROYALTY TRUST   NOTES TO FINANCIAL STATEMENTS 8. Contingencies   (continued) the Tenth Circuit affirmed the trial courts dismissal of the case and the U.S. Supreme Court has denied Grynbergs application for appeal. XTO Energy has entered into an agreement with the plaintiff whereby XTO Energy and the plaintiff dismissed all claims against each other. The court granted the dismissal of the claims on November 3, 2009, effectively ending this case. 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 certain royalty owners of natural gas wells in Oklahoma and Kansas. 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. At the class certification hearing, the plaintiffs sought to certify a class of royalty owners whose wells were connected to a processing plant owned by a subsidiary of XTO Energy in the Hugoton Field, with two sub-classes consisting of owners in Oklahoma and Kansas. In March 2009, the District Court granted the motion to certify the class. The plaintiffs filed a motion for summary judgment for only the two named plaintiffs. The court granted the motion in the amount of $12,779. A motion for summary judgment related to the remainder of the class is pending. Trial on the merits is scheduled for 2010. 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. The case
is set for trial in 2010. 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. It could, however, result in costs exceeding revenues on the properties underlying the Oklahoma and Kansas net profit interests for one or more monthly distributions, depending on the size of the judgment or settlement, if any, and the net proceeds being paid
at that time. 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 plaintiffs claims overlap the claims made by the plaintiffs in the Beer case as to certain properties. XTO
Energy has answered, denying all claims, and has filed motions to dismiss a portion of the claims. The federal court recently granted XTO Energys motion for summary judgment concerning prior settled class actions that overlap plaintiffs proposed class action. The court also granted XTO Energys motion to dismiss those portions of plaintiffs class that are currently being prosecuted in the Beer class action discussed above. 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. It could, however, result in costs exceeding revenues on the properties underlying the Oklahoma and Kansas net
 32    TABLE OF CONTENTS HUGOTON ROYALTY TRUST   NOTES TO FINANCIAL STATEMENTS 8. Contingencies   (continued) profit interests for one or more monthly distributions, depending on the size of the judgment or settlement, if any, and the net proceeds being paid at that time. 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, 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) Oil and Natural Gas Reserves The trusts proved oil and gas reserves have been estimated by independent petroleum engineers. Proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs and under existing economic conditions, operating methods, and government regulation before the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain. Proved developed reserves are the quantities expected to be recovered through existing wells with
existing equipment and operating methods in which the cost of the required equipment is relatively minor compared with the cost of a new well. Due to the inherent uncertainties and the limited nature of reservoir data, 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 estimate. Revisions result primarily from new information obtained from development drilling and production history and from changes in economic factors. Standardized Measure The standardized measure of discounted future net cash flows and changes in such cash flows are prepared using assumptions required by the Financial Accounting Standards Board. Such assumptions include the use of 12-month average prices for oil and gas, based on the first-day-of-the-month price for each month in the period for 2009, and year end costs for estimated future development and production expenditures to produce the proved reserves. Prior to 2009, standardized measure was calculated using year end oil and gas prices and costs. 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 working interest 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 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 (Note 3). The standardized measure does not represent managements estimate of our future cash flows or the value of proved oil and gas reserves. Probable and possible reserves, which may become proved in the future, are excluded from the calculations. Furthermore, prices used to determine the standardized measure are influenced by supply and demand as effected by recent economic conditions as well as other factors and may not be the most representative in estimating future revenues or reserve data.
 33    TABLE OF CONTENTS HUGOTON ROYALTY TRUST   NOTES TO FINANCIAL STATEMENTS 9. Supplemental Oil and Gas Reserve Information (Unaudited)   (continued) The average realized gas prices used to determine the standardized measure were $3.28 per Mcf in 2009, $4.47 per Mcf in 2008, $6.72 per Mcf in 2007 and $5.60 per Mcf in 2006. Oil prices used to determine the standardized measure were based on average realized oil prices of $57.17 per Bbl in 2009, $42.13 per Bbl in 2008, $95.73 per Bbl in 2007 and $58.02 per Bbl in 2006. In 2009, we used average oil and gas prices, based on the first-day-of-the-month price for each month in the period. For periods prior to 2009, we used year end oil and gas prices. Proved Reserves  Underlying Properties

          

          Net Profits InterestsGas(Mcf)

          

          Oil (Bbls)

          

          Gas(Mcf)

          

          Oil(Bbls)(in Thousands)Balance, December 31, 2006

          

          

          420,452

          

          

          

          3,838

          

          

          

          230,676

          

          

          

          2,195Extensions, additions and discoveries

          

          

          13,647

          

          

          

          167

          

          

          

          7,270

          

          

          

          89Revisions 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

          

          

          

          2,110Extensions, additions and discoveries

          

          

          10,493

          

          

          

          120

          

          

          

          3,432

          

          

          

          39Revisions 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

          

          

          

          1,682Extensions, additions and discoveries

          

          

          5,447

          

          

          

          354

          

          

          

          2,369

          

          

          

          154Revisions of prior estimates

          

          

          (21,865

          )

          

          

          (398

          )

          

          

          (55,473

          )

          

          

          (621

          )Production  sales volumes

          

          

          (26,642

          )

          

          

          (260

          )

          

          

          (8,326

          )

          

          

          (91

          )Balance, December 31, 2009

          

          

          323,245

          

          

          

          3,005

          

          

          

          117,053

          

          

          

          1,124
 Extensions, additions and discoveries in 2007, 2008 and 2009 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 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 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 InterestsGas(Mcf)

          

          Oil (Bbls)

          

          Gas(Mcf)

          

          Oil(Bbls)(in Thousands)December 31, 2006

          

          

          361,915

          

          

          

          3,369

          

          

          

          202,794

          

          

          

          1,964December 31, 2007

          

          

          352,732

          

          

          

          3,234

          

          

          

          198,187

          

          

          

          1,896December 31, 2008

          

          

          325,891

          

          

          

          2,960

          

          

          

          164,080

          

          

          

          1,554December 31, 2009

          

          

          283,864

          

          

          

          2,560

          

          

          

          110,050

          

          

          

          1,056
 34    TABLE OF CONTENTS HUGOTON ROYALTY TRUST   NOTES TO FINANCIAL STATEMENTS 9. Supplemental Oil and Gas Reserve Information (Unaudited)   (continued) Standardized Measure of Discounted Future Net Cash Flows from Proved Reserves  December 312009

          

          2008

          

          2007(in Thousands)Underlying PropertiesFuture cash inflows

          

          $

          1,231,607

          

          

          $

          1,786,971

          

          

          $

          3,061,372Future costs:Production

          

          

          640,707

          

          

          

          711,349

          

          

          

          1,014,076Development

          

          

          70,479

          

          

          

          66,456

          

          

          

          78,494Future net cash flows

          

          

          520,421

          

          

          

          1,009,166

          

          

          

          1,968,80210% discount factor

          

          

          245,392

          

          

          

          494,416

          

          

          

          992,874Standardized measure

          

          $

          275,029

          

          

          $

          514,750

          

          

          $

          975,928Net Profits InterestsFuture cash inflows

          

          $

          453,108

          

          

          $

          875,222

          

          

          $

          1,714,576Future production taxes

          

          

          36,771

          

          

          

          67,889

          

          

          

          139,535Future net cash flows

          

          

          416,337

          

          

          

          807,333

          

          

          

          1,575,04110% discount factor

          

          

          196,314

          

          

          

          395,533

          

          

          

          794,299Standardized measure

          

          $

          220,023

          

          

          $

          411,800

          

          

          $

          780,742
  Changes in Standardized Measure of Discounted Future Net Cash Flows from Proved Reserves  2009

          

          2008

          

          2007(in Thousands)Underlying PropertiesStandardized measure, January 1

          

          $

          514,750

          

          

          $

          975,928

          

          

          $

          798,688Revisions:Prices and costs

          

          

          (215,257

          )

          

          

          (365,784

          )

          

          

          208,352Quantity estimates

          

          

          (24,458

          )

          

          

          (9,546

          )

          

          

          (18,232

          )Accretion of discount

          

          

          44,852

          

          

          

          84,305

          

          

          

          69,710Future development costs

          

          

          (16,352

          )

          

          

          (28,435

          )

          

          

          (28,733

          )Production rates and other

          

          

          (1,090

          )

          

          

          (542

          )

          

          

          (1,708

          )Net revisions

          

          

          (212,305

          )

          

          

          (320,002

          )

          

          

          229,389Extensions, additions and discoveries

          

          

          10,310

          

          

          

          5,409

          

          

          

          35,122Production

          

          

          (58,726

          )

          

          

          (192,585

          )

          

          

          (130,021

          )Development costs

          

          

          21,000

          

          

          

          46,000

          

          

          

          42,750Net change

          

          

          (239,721

          )

          

          

          (461,178

          )

          

          

          177,240Standardized measure, December 31

          

          $

          275,029

          

          

          $

          514,750

          

          

          $

          975,928Net Profits InterestsStandardized measure, January 1

          

          $

          411,800

          

          

          $

          780,742

          

          

          $

          638,951Extensions, additions and discoveries

          

          

          8,248

          

          

          

          4,327

          

          

          

          28,097Accretion of discount

          

          

          35,882

          

          

          

          67,444

          

          

          

          55,768Revisions of prior estimates, changes in price and other

          

          

          (205,726

          )

          

          

          (323,445

          )

          

          

          128,426Net profits income

          

          

          (30,181

          )

          

          

          (117,268

          )

          

          

          (70,500

          )Standardized measure, December 31

          

          $

          220,023

          

          

          $

          411,800

          

          

          $

          780,742
 35    TABLE OF CONTENTS HUGOTON ROYALTY TRUST   NOTES TO FINANCIAL STATEMENTS 10. Quarterly Financial Data (Unaudited) The following is a summary of net profits income, distributable income and distributable income per unit by quarter for 2009 and 2008:  Net Profits Income

          

          Distributable Income

          

          Distributable Income per Unit2009First Quarter

          

          $

          5,777,425

          

          

          $

          5,465,360

          

          

          $

          0.136634Second Quarter

          

          

          4,537,110

          

          

          

          4,263,720

          

          

          

          0.106593Third Quarter

          

          

          8,533,583

          

          

          

          8,371,600

          

          

          

          0.209290Fourth Quarter

          

          

          11,332,762

          

          

          

          11,205,560

          

          

          

          0.280139$

          30,180,880

          

          

          $

          29,306,240

          

          

          $

          0.7326562008First Quarter

          

          $

          22,035,854

          

          

          $

          21,769,160

          

          

          $

          0.544229Second Quarter

          

          

          33,899,248

          

          

          

          33,554,920

          

          

          

          0.838873Third Quarter

          

          

          43,741,409

          

          

          

          43,688,640

          

          

          

          1.092216Fourth Quarter

          

          

          17,591,558

          

          

          

          17,481,680

          

          

          

          0.437042$

          117,268,069

          

          

          $

          116,494,400

          

          

          $

          2.912360
 36    TABLE OF CONTENTS 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, 2009 and 2008 and related statements of distributable income and changes in trust corpus for each of the years in the three-year period ended December 31, 2009. We also have audited Hugoton Royalty Trusts internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control  Integrated Frameworkissued 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, 2009 and 2008, and its distributable income and changes in trust corpus for each of the years in the three-year period ended December 31, 2009, 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, 2009, based on control criteria established in Internal Control  Integrated
Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission. KPMG LLP Fort Worth, Texas February 22, 2010
 37    TABLE OF CONTENTS 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, 2009. 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, 2009. The effectiveness of the trusts internal control over financial reporting as of December 31, 2009 has been audited by KPMG LLP, an independent registered public accounting firm, as stated in their report under Item 8, Financial Statements and Supplementary Data. There were no changes in the trusts internal control over financial reporting during the quarter ended December 31, 2009 that have materially affected, or are reasonably likely to materially affect, the trusts internal control over financial reporting. Item 9B. Other Information None.
 38    TABLE OF CONTENTS 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, 2009, other than one late filing of one transaction on Form 4 by Bob R. Simpson, the Chairman of the Board and Founder and Director of XTO Energy Inc. The transaction has 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, 17th Floor, 901 Main Street, Dallas, Texas 75202. Item 11. Executive Compensation The trustee received the following annual compensation from 2007 through 2009 as specified in the trust indenture:  Name and Principal Position

          

          Year

          

          Other Annual Compensation(1)U.S. Trust, Bank of America

          

          

          2009

          

          

          $

          48,126Private Wealth Management, Trustee

          

          

          2008

          

          

          

          45,6022007

          

          

          

          43,022
  (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 3, 2010, Bank of America, N.A. owned, in various fiduciary capacities, 235,017 units, with a shared right to vote 111,037 of these units and no right to vote 123,980 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, 2009 was approximately $911,000 per month, or $10,932,000 annually (net to the
 39    TABLE OF CONTENTS trust of $728,800 per month or $8,745,600 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 Item 2, Properties. See Item 11, Executive Compensation, for the remuneration received by the trustee from 2007 through 2009 and Item 12(b), Security Ownership of Management, for information concerning units owned by the trustee in various fiduciary capacities. As noted in 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. Item 14. Principal Accountant Fees and Services Fees for services performed by KPMG LLP for the years ended December 31, 2009 and 2008 are:  2009

          

          2008Audit fees

          

          $

          77,500

          

          

          $

          74,938Audit-related fees

          

          

          

          

          

          

          Tax fees

          

          

          

          

          

          

          All other fees

          

          

          

          

          

          

          $

          77,500

          

          

          $

          74,938
 As referenced in Item 10, Directors, Executive Officers and Corporate Governance, 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.
 40    TABLE OF CONTENTS PART IV Item 15. Exhibits and Financial Statement Schedules (a)

          The following documents are filed as a part of this report: 1.

          Financial Statements (included in Item 8 of this report) Independent Registered Public Accounting Firm Report Statements of Assets, Liabilities and Trust Corpus at December 31, 2009 and 2008 Statements of Distributable Income for the years ended December 31, 2009, 2008 and 2007 Statements of Changes in Trust Corpus for the years ended December 31, 2009, 2008 and 2007 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. (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 (99.1)

          Miller and Lents, Ltd. Report 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.
 41    TABLE OF CONTENTS 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., TRUSTEEBy/s/ Nancy G. WillisNancy G. WillisVice PresidentXTO ENERGY INC.Date: February 22, 2010By/s/ Louis G. BaldwinLouis G. BaldwinExecutive Vice President and Chief Financial Officer
 (The trust has no directors or executive officers.)
 42