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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, 2010 |  | Commission file number 1-10982



Cross Timbers Royalty Trust

(Exact name of registrant as specified in the Cross Timbers Royalty Trust Indenture)



|                                                               |  |                                     
|-------------------------------------------------------------- |  | ------------------------------------
|Texas                                                          |  | 75-6415930                          
|(State or other jurisdiction of
incorporation or organization) |  | (I.R.S. Employer Identification No.)



|                                         |  |           
|---------------------------------------- |  | ----------
|U.S. Trust, Bank of America              |  |           
|Private Wealth Management                |  |           
|Trustee                                  |  |           
|P.O. Box 830650                          |  |           
|Dallas, Texas                            |  | 75283-0650
|(Address of principal executive offices) |  | (Zip Code)



Registrants telephone number including area code: (877) 228-5084



Securities registered pursuant to Section 12(b) of
the Act:



|                             |  |                                          
|---------------------------- |  | -----------------------------------------
|Title of each
class          |  | Name of each exchange on which
registered
|Units of Beneficial Interest |  | New York Stock Exchange                  



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



Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the
Securities Act. Yes ̈Nox



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 ̈Nox



Indicate by check mark whether the registrant (1) has
filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been
subject to such filing requirements for the past 90 days. YesxNo   ̈



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   ̈    No   ̈



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.  x



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



Indicate by check mark whether the registrant is a shell
company (as defined in Exchange Act Rule 12b-2). Yes   ̈    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, 2010 (the last business day of its most recently completed second fiscal quarter), held by non-affiliates of the registrant on that date was
approximately $194 million.



At February 16,
2011, there were 6,000,000 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



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CROSS TIMBER
ROYALTY TRUST



2010 ANNUAL REPORT ON FORM
10-K



TABLE OF CONTENTS



|         |  |                                                                                               |  |      |    | 
|-------- |  | --------------------------------------------------------------------------------------------- |  | ---- | -- | 
|         |  |                                                                                               |  | Page |   
|         |  | Glossary of Terms                                                                             |  |      | 1  | 
|Part I   | 
|Item 1.  |  | Business                                                                                      |  |      | 2  | 
|Item 1A. |  | Risk Factors                                                                                  |  |      | 4  | 
|Item 1B. |  | Unresolved Staff Comments                                                                     |  |      | 8  | 
|Item 2.  |  | Properties                                                                                    |  |      | 8  | 
|Item 3.  |  | Legal Proceedings                                                                             |  |      | 15 | 
|Item 4.  |  | [Removed and Reserved]                                                                        |  |      | 15 | 
|Part II  | 
|Item 5.  |  | Market for Units of the Trust, Related Unitholder Matters and Trust Purchases of
Units        |  |      | 16 | 
|Item 6.  |  | Selected Financial Data                                                                       |  |      | 16 | 
|Item 7.  |  | Trustees Discussion and Analysis of Financial Condition and Results of Operations            |  |      | 17 | 
|Item 7A. |  | Quantitative and Qualitative Disclosures about Market Risk                                    |  |      | 23 | 
|Item 8.  |  | Financial Statements and Supplementary Data                                                   |  |      | 23 | 
|Item 9.  |  | Changes in and Disagreements with Accountants on Accounting and Financial Disclosure          |  |      | 35 | 
|Item 9A. |  | Controls and Procedures                                                                       |  |      | 35 | 
|Item 9B. |  | Other Information                                                                             |  |      | 35 | 
|Part III | 
|Item 10. |  | Directors, Executive Officers and Corporate Governance                                        |  |      | 35 | 
|Item 11. |  | Executive Compensation                                                                        |  |      | 36 | 
|Item 12. |  | Security Ownership of Certain Beneficial Owners and Management and Related Unitholder
Matters |  |      | 36 | 
|Item 13. |  | Certain Relationships and Related Transactions, and Director Independence                     |  |      | 36 | 
|Item 14. |  | Principal Accountant Fees and Services                                                        |  |      | 37 | 
|Part IV  | 
|Item 15. |  | Exhibits and Financial Statement Schedules                                                    |  |      | 37 | 



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Glossary of Terms



The following is a glossary of certain defined terms used in
this Annual Report on Form 10-K.



GLOSSARY



|                                                  |  |                                                                                                                                                                                                                                                                                                                                                
|------------------------------------------------- |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|                                                  | 
|Bbl                                               |  | Barrel (of oil)                                                                                                                                                                                                                                                                                                                                
|                                                  | 
|Bcf                                               |  | Billion cubic feet (of natural gas)                                                                                                                                                                                                                                                                                                            
|                                                  | 
|Mcf                                               |  | Thousand cubic feet (of natural gas)                                                                                                                                                                                                                                                                                                           
|                                                  | 
|MMBtu                                             |  | One million British Thermal Units, a common energy measurement                                                                                                                                                                                                                                                                                 
|                                                  | 
|net proceeds                                      |  | Gross proceeds received by XTO Energy from sale of production from the underlying properties, less applicable costs, as defined in the net profits interest
conveyances                                                                                                                                                                        
|                                                  | 
|net profits income                                |  | Net proceeds multiplied by the applicable net profits percentage of 75% or 90%, which is paid to the trust by XTO Energy. Net profits income is referred to as
royalty income for income tax 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:                                                                                               
|                                                  | 
|                                                  |  | 90% net profits interestsinterests that entitle the trust to receive 90% of the net proceeds from the underlying properties that are royalty or overriding royalty
interests in Texas, Oklahoma and New Mexico                                                                                                                                
|                                                  | 
|                                                  |  | 75% net profits interestsinterests that entitle the trust to receive 75% of the net proceeds from the underlying properties that are working interests in Texas and
Oklahoma                                                                                                                                                                  
|                                                  | 
|royalty interest (and overridingroyalty interest) |  | A nonoperating interest in an oil and gas property that provides the owner a specified share of production without any production expense or development
costs                                                                                                                                                                                 
|                                                  | 
|underlying properties                             |  | XTO Energys interest in certain oil and gas properties from which the net profits interests were conveyed. The underlying properties include royalty and overriding royalty
interests in producing and nonproducing properties in Texas, Oklahoma and New Mexico, and working interests in producing properties located in Texas and Oklahoma.
|                                                  | 
|working interest                                  |  | An operating interest in an oil and gas property that provides the owner a specified share of production that is subject to all production expense and development
costs                                                                                                                                                                       



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PART I



|Item 1. | Business
|------- | --------



Cross Timbers Royalty Trust is an express trust created under the laws of Texas pursuant to the Cross Timbers Royalty Trust Indenture
entered into on February 12, 1991 between predecessors of XTO Energy Inc. (formerly known as Cross Timbers Oil Company), as grantors, and NCNB Texas National Bank, as trustee. Bank of America, 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 877-228-5084).



The trusts internet web site is
www.crosstimberstrust.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.



On February 12, 1991,
the predecessors of XTO Energy conveyed defined net profits interests to the trust under five separate conveyances:



| |  | one in each of the states of Texas, Oklahoma and New Mexico, to convey a 90% defined net profits interest carved out of substantially all royalty and overriding royalty
interests owned by the predecessors in those states, and
| | - | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  | one in each of the states of Texas and Oklahoma, to convey a 75% defined net profits interest carved out of specific working interests owned by the predecessors in
those states.
| | - | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



The conveyance of
these net profits interests was effective for production from October 1, 1990. The net profits interests and the underlying properties are further described under Item 2, Properties.



In exchange for the net profits interests conveyed to the trust, the predecessors of XTO Energy received
6,000,000 units of beneficial interest of the trust. Predecessors of XTO Energy distributed units to their owners in February 1991 and November 1992, and in February 1992, sold units in the trusts initial public offering. Units are listed and
traded on the New York Stock Exchange under the symbol CRT. XTO Energy currently is not a unitholder of the trust.



On June 25, 2010, XTO Energy became a wholly owned subsidiary of Exxon Mobil Corporation. The merger is not expected to have a
material effect on trust annual distributable income, financial position or liquidity.



Under the terms of each of the five conveyances, the trust receives net profits income from the net profits interests generally on the last business day of each month. Net profits income is determined by
XTO Energy by multiplying the net profit percentage (90% or 75%) times net proceeds from the underlying properties for each conveyance during the previous month. Net proceeds are the gross proceeds received from the sale of production, less
production costs, as defined in the conveyances. For the 90% net profits interests and the 75% net profits interests, production costs generally include applicable property taxes, transportation, marketing and other charges. For the 75%
net profits interests only, production costs also include capital and operating costs paid (e.g., drilling, production and other direct costs of owning and operating the property) and a monthly overhead charge that is adjusted annually. The monthly
overhead charge at December 31, 2010 was $34,481 ($25,861 net to the trust). XTO Energy also deducts an overhead charge as operator of the Penwell Unit and ExxonMobil deducts an overhead charge as operator of the Hewitt Unit. As of
December 31, 2010, monthly overhead



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attributable to the Penwell Unit was $2,713 ($2,035 net to the trust) and monthly overhead attributable to the Hewitt Unit was $4,538 ($3,404 net to the trust). If production costs exceed gross
proceeds for any conveyance, this excess is carried forward to future monthly computations of net proceeds until the excess costs (plus interest accrued as specified in the conveyances) are completely recovered. Excess production costs and related
accrued interest from one conveyance cannot be used to reduce net proceeds from any other conveyance.



Costs exceeded revenues on properties underlying the Texas working interest for January through April 2009 and on properties underlying
the Oklahoma working interest for February through April 2009. There were no excess costs in 2010. 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 the 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.



Approximately 20 of the underlying royalty interests in the San Juan Basin burden working interests in properties operated by XTO Energy. XTO Energy also operates the Penwell Unit which is one of the
properties underlying the Texas 75% net profits interests and ExxonMobil operates the Hewitt Unit which is one of the properties underlying the Oklahoma 75% net profits interests. Other than these properties, XTO Energy and ExxonMobil do not operate
or control any of the underlying properties or related working interests.



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 that is a working interest if it is incapable of producing in paying quantities, as
determined by XTO Energy.



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.



Net profits income received by the trust on or before the
last business day of the month is generally attributable to oil production two months prior and gas production three months prior. The monthly distribution amount to unitholders is determined by:



Adding



| | (1) | net profits income received,
| | --- | ----------------------------

| | (2) | estimated interest income to be received on the monthly distribution amount, including an adjustment for the difference between the estimated and actual interest
received for the prior monthly distribution amount,
| | --- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| | (3) | cash available as a result of reduction of cash reserves, and
| | --- | -------------------------------------------------------------

| | (4) | other cash receipts, then
| | --- | -------------------------



Subtracting



| | (1) | liabilities paid and
| | --- | --------------------

| | (2) | the reduction in cash available due 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.



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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 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 60% of the net profits income received by the trust during 2010, as well as 63% of the estimated proved reserves of the net
profits interests at December 31, 2010 (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 is
generally a greater demand for gas during the winter. Otherwise, trust income is not subject to seasonal factors, nor dependent upon patents, licenses, franchises or concessions. The trust conducts no research activities.



The oil and gas industry is highly competitive in all its
phases. Operators of the properties in which the trust holds interests encounter competition from other oil and gas companies and from individual producers and operators. Oil and natural gas are commodities, for which market prices are determined by
external supply and demand factors.



|Item 1A. | Risk Factors
|-------- | ------------



The following factors 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 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, natural gas and
natural gas liquids, consumer demand, the price and availability of alternative fuels, the proximity to, and capacity of, transportation facilities



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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 from the properties underlying the 75% net profits interests.



Production expense and development costs are deducted in the
calculation of the trusts share of net proceeds from properties underlying the 75% net profits interests. 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 for its 75% net profits interests. If development costs and production expense for properties underlying the 75% net profits in a particular state exceed the production proceeds from the properties (as was
the case with respect to the properties underlying the Texas working interest for January through April 2009 and the properties underlying the Oklahoma working interest for February through April 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 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 75% 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 from properties underlying the 75% net profits interests, and would therefore reduce trust distributions by the amount of
such uninsured costs.



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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.



Because XTO Energy does not operate most of the underlying
properties, it is unable to significantly influence the operations 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 the other operators of the underlying
properties must adhere to the standard of a prudent operator, they are under no obligation to continue operating the properties. Neither the trustee nor trust unitholders have the right to replace an operator.



The assets of the trust represent interests in depleting assets and, if
XTO Energy or 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 hydrocarbons from depleting assets. 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 and can offset the reduction in proved reserves. The timing and size of these projects will depend on the market prices of oil and natural gas. If the
operator(s) of the properties do not implement additional maintenance and development projects, the future rate of production decline of proved reserves may be higher than the rate currently expected by the trust. Because the net proceeds payable to
the trust are derived from the sale of hydrocarbons from depleting assets, the portion of distributions to unitholders attributable to depletion may be considered a return on capital as opposed to a return on investment. Distributions that are a
return of capital will ultimately diminish the depletion tax benefits available to the unitholders, which could reduce the market value of the units over time. Eventually, the properties underlying the trusts net profits interest will cease to
produce in commercial quantities and the trust will, therefore, cease to receive any net proceeds therefrom.



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.



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



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



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



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



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



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



Trust unitholders have limited voting rights and have limited ability to enforce the trusts rights against XTO Energy or any other operator 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 or Exxon Mobil Corporation.



The trust indenture and related trust law permit the trustee and the trust to sue XTO Energy or any other operator 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 operator 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



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protection to trust unitholders. While the trustee is liable for any excess liabilities incurred if the trustee fails to ensure that such liabilities are to be satisfied only out of trust assets,
under the laws of Texas, which are unsettled on this point, a unitholder may be jointly and severally liable for any liability of the trust if the satisfaction of such liability was not contractually limited to the assets of the trust and the assets
of the trust and the trustee are not adequate to satisfy such liability. As a result, trust unitholders may be exposed to personal liability. The trust, however, is not liable for production costs or other liabilities of the underlying properties.



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



Drilling oil and natural gas wells involves numerous risks, including the risk that commercially productive oil and natural gas reservoirs are not encountered. The presence of unanticipated pressures or
irregularities in formations, miscalculations or accidents may cause drilling activities to be unsuccessful. In addition, there is often uncertainty as to the future cost or timing of drilling, completing and operating wells. Further, development
activities may be curtailed, delayed or canceled as a result of a variety of factors, including:



| |  |  | unexpected drilling conditions;
| | - |  | -------------------------------

| |  |  | title problems;
| | - |  | ---------------

| |  |  | restricted access to land for drilling or laying pipeline;
| | - |  | ----------------------------------------------------------

| |  |  | pressure or irregularities in formations;
| | - |  | -----------------------------------------

| |  |  | equipment failures or accidents;
| | - |  | --------------------------------

| |  |  | adverse weather conditions; and
| | - |  | -------------------------------

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



While these risks do not expose the trust to liabilities of
the drilling contractor or operator of the well, they can reduce net proceeds payable to the trust and trust distributions by decreasing oil and gas revenues or increasing production expense or development costs from the underlying properties.
Furthermore, these risks may cause the costs of development activities on properties underlying the 75% net profits interests to exceed the revenues therefrom, thereby reducing net proceeds payable to the trust and trust distributions.



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



Extensive federal, state and local regulation of the oil and natural gas industry significantly affects operations on the underlying
properties. In particular, oil and natural gas development and production are subject to stringent environmental regulations. These regulations have increased the costs of planning, designing, drilling, installing, operating and abandoning oil and
natural gas wells and other related facilities, which costs could reduce net proceeds payable to the trust and trust distributions. These regulations may become more demanding in the future.



|Item 1B. | Unresolved Staff Comments
|-------- | -------------------------



As of December 31, 2010, 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 asset, with the exception of certain
short-term investments as specified under Item 1, Business. The trustee is prohibited from selling any portion of the net profits interests unless approved by at least 80% of the unitholders or at such time as trust gross revenue is less than
$1 million for two successive years.



8



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##### Table of Contents

The net profits interests comprise:



the 90% net profits interests which are
carved from:



| | a) | producing royalty and overriding royalty interest properties in Texas, Oklahoma and New Mexico, and
| | -- | ---------------------------------------------------------------------------------------------------



| | b) | 11.11% nonparticipating royalty interests in nonproducing properties located primarily in Texas and Oklahoma; and
| | -- | -----------------------------------------------------------------------------------------------------------------



the 75% net profits interests which are carved from working
interests in four properties in Texas and three properties in Oklahoma.



All underlying royalties, underlying nonproducing royalties and underlying working interest 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 include over 2,900 producing properties with established production histories in Texas, Oklahoma and New Mexico. The average reserve-to-production index for the underlying
properties as of December 31, 2010 is approximately 12 years. This index is calculated using total proved reserves and estimated 2011 production for the underlying properties. The projected 2011 production is from proved developed producing
reserves as of December 31, 2010. 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 37% oil and 63% natural gas. The underlying properties also include certain nonproducing properties in Texas, Oklahoma and New Mexico that are primarily mineral interests.



Producing Acreage, Wells and Drilling



90% Net Profits Interests Underlying Royalties.Royalty and overriding royalty properties underlying the 90% net profits interests represent 79% of the discounted future net cash flows from trust proved reserves at December 31, 2010. Approximately 78% of the discounted future net cash
flows from the 90% net profits interests is from gas reserves, totaling 24.8 Bcf. Oil reserves allocated to the 90% net profits interests are primarily located in West Texas and are estimated to be 503,000 Bbls at December 31, 2010.



The underlying royalties are royalty and overriding royalty
interests primarily located in mature producing oil and gas fields. The most significant producing region in which the underlying royalties are located is the San Juan Basin in northwestern New Mexico. The San Juan Basin royalties gas production
accounted for approximately 79% of the trusts gas sales volumes and 46% of the net profits income for 2010. The trusts estimated proved gas reserves from this region totaled 20.1 Bcf at December 31, 2010, or approximately 81%
of trust total gas reserves at that date. XTO Energy estimates that underlying royalties in the San Juan Basin include more than 4,628 gross (approximately 47.7 net) wells, covering almost 60,000 gross acres. Approximately half of these wells are
operated by BP America Production Company or ConocoPhillips. Production from conventional gas wells is primarily from the Dakota, Mesaverde and Pictured Cliffs formations.



Most of the trusts San Juan Basin gas has been approved
for increased density drilling. In 1999, the Mesaverde was approved for increased density drilling, and in 2002 the Fruitland Coal was approved for increased density drilling, which doubled the number of drill wells allowed per spacing unit. XTO
Energy has advised the trustee that the trust has received net proceeds from additional development wells in recent years and that it believes operators will continue to pursue increased density drilling, but the potential effect on the trust is
unknown.



Eastward pipeline capacity was added in
the San Juan Basin in the recent past, reducing the dependence of this gas on California markets and effectively increasing San Juan Basin gas prices in relation to prices from other regions. Gas-powered electricity generation is increasing in the
southwest, and future pipelines are being discussed.



9



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##### Table of Contents

The underlying royalties also include royalties in the Sand Hills field of Crane County,
Texas. Most of these properties are operated by major operators. The Sand Hills field was discovered in 1931 and includes production from three main intervals, the Tubb, McKnight and Judkins. Development potential for the field includes
recompletions and additional infill drilling.



The
underlying royalties contain approximately 220,286 gross (approximately 32,183 net) producing acres. Well counts for the underlying royalties cannot be provided because information regarding the number of wells on royalty properties is generally not
made available to royalty interest owners.



Because the properties related to the 90% net profits interests are primarily royalty interests and overriding royalty interests, net
profits income from these properties is not reduced by production expense or development costs. Additionally, net profits income from these interests cannot be reduced by any excess costs of the 75% net profits interests. The trust, therefore,
should generally receive monthly net profits income from these interests, as determined by oil and gas sales volumes and prices.



75% Net Profits Interests Underlying Working Interest Properties.Underlying the 75% net profits interests are working interests in
seven large, predominantly oil-producing properties in Texas and Oklahoma operated primarily by established oil companies. These properties are located in mature fields undergoing secondary or tertiary recovery operations. Most of the oil produced
from the 75% net profits interest properties is sour oil, which is sold at a decrement to NYMEX sweet crude oil prices. XTO Energy is the operator of the Penwell Unit, which is one of the properties underlying the Texas 75% net profits interests and
ExxonMobil is the operator of the Hewitt Unit, which is one of the properties underlying the Oklahoma 75% net profits interests. With the exception of the Penwell Unit and Hewitt Unit, XTO Energy and ExxonMobil generally have little influence or
control over operations on any of these properties.



Proved reserves from the 75% net profits interests are almost entirely oil, estimated to be approximately 561,000 Bbls at year-end 2010.
Proved reserves from these interests represent 21% of the discounted future net cash flows of the trusts proved reserves at December 31, 2010.



The underlying working interest properties are detailed below:



|                        |  |                 |  |                               |  |                        |      |   |                 |  |     |  
|----------------------- |  | --------------- |  | ----------------------------- |  | ---------------------- | ---- | - | --------------- |  | --- | -
|                        |  |                 |  |                               |  | Ownership ofXTO
Energy |     
|Unit                    |  | County/State    |  | Operator                      |  | WorkingInterest        |      |   | RevenueInterest | 
|North Cowden            |  | Ector/Texas     |  | Occidental Permian, Ltd.      |  |                        | 1.7  | % |                 |  | 1.4 | %
|North Central Levelland |  | Hockley/Texas   |  | Apache Corporation            |  |                        | 3.2  | % |                 |  | 2.1 | %
|Penwell                 |  | Ector/Texas     |  | XTO Energy Inc.               |  |                        | 5.2  | % |                 |  | 4.6 | %
|Sharon Ridge Canyon     |  | Borden/Texas    |  | Occidental Permian, Ltd.      |  |                        | 4.3  | % |                 |  | 2.8 | %
|Hewitt                  |  | Carter/Oklahoma |  | Exxon Mobil Corporation       |  |                        | 11.3 | % |                 |  | 9.9 | %
|Wildcat Jim Penn        |  | Carter/Oklahoma |  | Noble Energy Production, Inc. |  |                        | 8.6  | % |                 |  | 7.5 | %
|South Graham Deese      |  | Carter/Oklahoma |  | Linn Energy, LLC              |  |                        | 9.2  | % |                 |  | 8.7 | %



The underlying working interest properties consist of 3,813 gross (3,046 net) producing acres. As of December 31, 2010, there were 1,430 gross (61.5 net) productive oil wells and no wells in process
of drilling on these properties. There were no wells drilled in 2010 and 2009, as compared with three gross (0.3 net) wells drilled in 2008.



Because these underlying properties are working interests, production expense and development costs are deducted in calculating net
profits income from the 75% net profits interests. As a result, net profits income from these interests is affected by the level of maintenance and development activity on these underlying properties. Net profits income is also dependent upon oil
and gas sales volumes and prices and is subject to reduction for any prior period excess costs.



10



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##### Table of Contents

Total 2010 development costs were $539,048 down 10% from 2009 development costs of $601,502.
Development costs were lower in 2010 because of decreased development activity related to Texas and Oklahoma properties underlying the 75% net profits interest. January and February 2011 development costs totaled approximately $141,000, primarily
incurred in fourth quarter 2010.



As reported to
XTO Energy by unit operators in February of each year, budgeted development costs were $585,000 for 2010 and $756,000 for 2009. Actual development costs often differ from amounts budgeted because of changes in product prices and other factors that
may affect the timing or selection of projects. Also, costs are deducted in the calculation of trust net profits income several months after they are incurred by the operator. Unit operators have reported total budgeted costs, net to the underlying
properties, of approximately $907,000 for 2011 and $881,000 for 2012.



Costs exceeded revenues on properties underlying the Texas working interest for January through April 2009 and on properties underlying the Oklahoma working interest for February through April 2009. There
were no excess costs in 2008 or 2010. For information regarding the effect of excess costs on trust net profits income, see Trustees Discussion and Analysis of Financial Condition and Results of Operations, under Item 7.



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, 2010:



|                          |  |                       |       |  |                         |              |        |                                                   |            |  |          |  |  |  |        |  |  |   |         |  |  |   |        | 
|------------------------- |  | --------------------- | ----- |  | ----------------------- | ------------ | ------ | ------------------------------------------------- | ---------- |  | -------- |  |  |  | ------ |  |  | - | ------- |  |  | - | ------ | 
|                          |  | Underlying Properties |       |  | Net Profits Interests   |             
|                          |  | Proved Reserves (a)   |       |  | Proved Reserves (a) (b) |              |        | Future Net Cash Flowsfrom Proved Reserves (a) (c) |           
|                          |  | Oil(Bbls)             |       |  | Gas(Mcf)                |              |        | Oil(Bbls)                                         |            |  | Gas(Mcf) |  | 
|(in thousands)            |  |                       |       |  |                         | Undiscounted |        |                                                   | Discounted | 
|90% Net Profits Interests |  |                       |       |  |                         |              |        |                                                   |            |  |          |  |  |  |        |  |  |   |         |  |  |   |        | 
|San Juan Basin            |  |                       | 35    |  |                         |              | 22,385 |                                                   |            |  | 31       |  |  |  | 20,146 |  |  | $ | 103,063 |  |  | $ | 48,390 | 
|Other New Mexico          |  |                       | 46    |  |                         |              | 133    |                                                   |            |  | 42       |  |  |  | 125    |  |  |   | 3,552   |  |  |   | 1,783  | 
|Texas                     |  |                       | 424   |  |                         |              | 3,397  |                                                   |            |  | 381      |  |  |  | 3,055  |  |  |   | 43,038  |  |  |   | 22,142 | 
|Oklahoma                  |  |                       | 55    |  |                         |              | 1,713  |                                                   |            |  | 49       |  |  |  | 1,440  |  |  |   | 9,192   |  |  |   | 4,832  | 
|                          |  |                       |       |  |                         |              |        |                                                   |            |  |          |  |  |  |        |  |  |   |         |  |  |   |        | 
|Total                     |  |                       | 560   |  |                         |              | 27,628 |                                                   |            |  | 503      |  |  |  | 24,766 |  |  |   | 158,845 |  |  |   | 77,147 | 
|                          |  |                       |       |  |                         |              |        |                                                   |            |  |          |  |  |  |        |  |  |   |         |  |  |   |        | 
|75% Net Profits Interests |  |                       |       |  |                         |              |        |                                                   |            |  |          |  |  |  |        |  |  |   |         |  |  |   |        | 
|Texas                     |  |                       | 768   |  |                         |              | 318    |                                                   |            |  | 276      |  |  |  | 114    |  |  |   | 20,247  |  |  |   | 10,374 | 
|Oklahoma                  |  |                       | 976   |  |                         |              | 126    |                                                   |            |  | 285      |  |  |  | 37     |  |  |   | 18,702  |  |  |   | 10,602 | 
|                          |  |                       |       |  |                         |              |        |                                                   |            |  |          |  |  |  |        |  |  |   |         |  |  |   |        | 
|Total                     |  |                       | 1,744 |  |                         |              | 444    |                                                   |            |  | 561      |  |  |  | 151    |  |  |   | 38,949  |  |  |   | 20,976 | 
|                          |  |                       |       |  |                         |              |        |                                                   |            |  |          |  |  |  |        |  |  |   |         |  |  |   |        | 
|TOTAL                     |  |                       | 2,304 |  |                         |              | 28,072 |                                                   |            |  | 1,064    |  |  |  | 24,917 |  |  | $ | 197,794 |  |  | $ | 98,123 | 
|                          |  |                       |       |  |                         |              |        |                                                   |            |  |          |  |  |  |        |  |  |   |         |  |  |   |        | 

---

|(a) | Based on 12-month average oil price of $73.20 per Bbl and $5.42 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 increased 38% from year-end 2009 to 2010, primarily because of a 36% increase in oil prices and a 33% increase in natural gas prices.
|--- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



|(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%.
|--- | --------------------------------------------------------------------------------------------------------------------------------------------------------------



11



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##### Table of Contents

Proved reserves consist of the following:



|                            |  |                       |       |  |                       |  |        |           |  |  |          |  |  |  |        |  |  |  |  | 
|--------------------------- |  | --------------------- | ----- |  | --------------------- |  | ------ | --------- |  |  | -------- |  |  |  | ------ |  |  |  |  | 
|                            |  | Underlying Properties |       |  | Net Profits Interests |  |        |           |  | 
|                            |  | Proved Reserves       |       |  | Proved Reserves       |  |        |           |  | 
|(in thousands)              |  | Oil(Bbls)             |       |  | Gas(Mcf)              |  |        | Oil(Bbls) |  |  | Gas(Mcf) |  |  |  |        | 
|Proved developed reserves   |  |                       | 2,304 |  |                       |  | 28,072 |           |  |  | 1,064    |  |  |  | 24,917 |  |  |  |  | 
|Proved undeveloped reserves |  |                       |      |  |                       |  |       |           |  |  |         |  |  |  |       |  |  |  |  | 
|                            |  |                       |       |  |                       |  |        |           |  |  |          |  |  |  |        |  |  |  |  | 
|Total proved reserves       |  |                       | 2,304 |  |                       |  | 28,072 |           |  |  | 1,064    |  |  |  | 24,917 |  |  |  |  | 
|                            |  |                       |       |  |                       |  |        |           |  |  |          |  |  |  |        |  |  |  |  | 



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, 2010, 2009, 2008 and 2007. 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 75% net profits interests in the
working interest properties have effectively been reduced to reflect recovery of the trusts 75% 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.



12



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##### 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 oil production and three months after gas production. Oil and gas production and average sales prices attributable to the underlying
properties and the net profits interests for each of the three years ended December 31, 2010 were as follows:



|                       |  |                           |           |  |                           |  |           |       |  |  |           |  |  |      |         |  |      |  |         |      |  |  |         |  |  |      |           |  |  |  |           |  |  |  |           | 
|---------------------- |  | ------------------------- | --------- |  | ------------------------- |  | --------- | ----- |  |  | --------- |  |  | ---- | ------- |  | ---- |  | ------- | ---- |  |  | ------- |  |  | ---- | --------- |  |  |  | --------- |  |  |  | --------- | 
|                       |  | 90% Net Profits Interests |           |  | 75% Net Profits Interests |  |           | Total | 
|                       |  | 2010                      |           |  | 2009                      |  |           | 2008  |  |  | 2010      |  |  | 2009 |         |  | 2008 |  |         | 2010 |  |  | 2009    |  |  | 2008 |          
|Production             |  |                           |           |  |                           |  |           |       |  |  |           |  |  |      |         |  |      |  |         |      |  |  |         |  |  |      |           |  |  |  |           |  |  |  |           | 
|                       |  |                           |           |  |                           |  |           |       | 
|Underlying Properties  |  |                           |           |  |                           |  |           |       |  |  |           |  |  |      |         |  |      |  |         |      |  |  |         |  |  |      |           |  |  |  |           |  |  |  |           | 
|                       |  |                           |           |  |                           |  |           |       | 
|OilSales (Bbls)       |  |                           | 61,282    |  |                           |  | 68,326    |       |  |  | 68,345    |  |  |      | 135,820 |  |      |  | 151,154 |      |  |  | 155,951 |  |  |      | 197,102   |  |  |  | 219,480   |  |  |  | 224,296   | 
|Average per day (Bbls) |  |                           | 168       |  |                           |  | 187       |       |  |  | 187       |  |  |      | 372     |  |      |  | 414     |      |  |  | 426     |  |  |      | 540       |  |  |  | 601       |  |  |  | 613       | 
|GasSales (Mcf)        |  |                           | 2,054,352 |  |                           |  | 1,975,850 |       |  |  | 2,017,442 |  |  |      | 43,612  |  |      |  | 50,758  |      |  |  | 61,908  |  |  |      | 2,097,964 |  |  |  | 2,026,608 |  |  |  | 2,079,350 | 
|Average per day (Mcf)  |  |                           | 5,628     |  |                           |  | 5,413     |       |  |  | 5,512     |  |  |      | 120     |  |      |  | 139     |      |  |  | 169     |  |  |      | 5,748     |  |  |  | 5,552     |  |  |  | 5,681     | 
|                       |  |                           |           |  |                           |  |           |       | 
|Net Profits Interests  |  |                           |           |  |                           |  |           |       |  |  |           |  |  |      |         |  |      |  |         |      |  |  |         |  |  |      |           |  |  |  |           |  |  |  |           | 
|                       |  |                           |           |  |                           |  |           |       | 
|OilSales (Bbls)       |  |                           | 51,014    |  |                           |  | 58,833    |       |  |  | 59,597    |  |  |      | 48,614  |  |      |  | 17,005  |      |  |  | 69,444  |  |  |      | 99,628    |  |  |  | 75,838    |  |  |  | 129,041   | 
|Average per day (Bbls) |  |                           | 140       |  |                           |  | 161       |       |  |  | 163       |  |  |      | 133     |  |      |  | 47      |      |  |  | 190     |  |  |      | 273       |  |  |  | 208       |  |  |  | 353       | 
|GasSales (Mcf)        |  |                           | 1,821,708 |  |                           |  | 1,761,108 |       |  |  | 1,799,599 |  |  |      | 15,181  |  |      |  | 7,370   |      |  |  | 25,548  |  |  |      | 1,836,889 |  |  |  | 1,768,478 |  |  |  | 1,825,147 | 
|Average per day (Mcf)  |  |                           | 4,991     |  |                           |  | 4,825     |       |  |  | 4,917     |  |  |      | 42      |  |      |  | 20      |      |  |  | 70      |  |  |      | 5,033     |  |  |  | 4,845     |  |  |  | 4,987     | 
|                       |  |                           |           |  |                           |  |           |       | 
|Average Sales Price    |  |                           |           |  |                           |  |           |       |  |  |           |  |  |      |         |  |      |  |         |      |  |  |         |  |  |      |           |  |  |  |           |  |  |  |           | 
|                       |  |                           |           |  |                           |  |           |       | 
|Oil (per Bbl)          |  |                           | $73.52    |  |                           |  | $54.94    |       |  |  | $100.53   |  |  |      | $71.03  |  |      |  | $48.96  |      |  |  | $99.31  |  |  |      | $71.80    |  |  |  | $50.82    |  |  |  | $99.68    | 
|Gas (per Mcf)          |  |                           | $7.11     |  |                           |  | $5.64     |       |  |  | $11.84    |  |  |      | $4.66   |  |      |  | $3.26   |      |  |  | $7.15   |  |  |      | $7.06     |  |  |  | $5.58     |  |  |  | $11.70    | 



Oil and gas production by conveyance attributable to the underlying properties for each of the three years ended December 31, 2010
were as follows:



|                            |  |                                  |           |  |      |  |           |      |  |  |           | 
|--------------------------- |  | -------------------------------- | --------- |  | ---- |  | --------- | ---- |  |  | --------- | 
|                            |  | Underlying Gas Production (Mcf)  |          
|Conveyance                  |  | 2010                             |           |  | 2009 |  |           | 2008 | 
|New Mexico royalty interest |  |                                  | 1,608,164 |  |      |  | 1,429,350 |      |  |  | 1,516,271 | 
|Oklahoma royalty interest   |  |                                  | 186,526   |  |      |  | 261,355   |      |  |  | 194,506   | 
|Texas royalty interest      |  |                                  | 259,662   |  |      |  | 285,146   |      |  |  | 306,666   | 
|Texas working interest      |  |                                  | 31,109    |  |      |  | 31,591    |      |  |  | 38,381    | 
|Oklahoma working interest   |  |                                  | 12,503    |  |      |  | 19,166    |      |  |  | 23,526    | 
|                            |  |                                  |           |  |      |  |           |      |  |  |           | 
|Total                       |  |                                  | 2,097,964 |  |      |  | 2,026,608 |      |  |  | 2,079,350 | 
|                            |  |                                  |           |  |      |  |           |      |  |  |           | 
|                            | 
|                            |  | Underlying Oil Production (Bbls) |          
|Conveyance                  |  | 2010                             |           |  | 2009 |  |           | 2008 | 
|New Mexico royalty interest |  |                                  | 7,669     |  |      |  | 8,393     |      |  |  | 9,049     | 
|Oklahoma royalty interest   |  |                                  | 6,466     |  |      |  | 7,185     |      |  |  | 8,310     | 
|Texas royalty interest      |  |                                  | 47,147    |  |      |  | 52,748    |      |  |  | 50,986    | 
|Texas working interest      |  |                                  | 60,639    |  |      |  | 67,088    |      |  |  | 69,852    | 
|Oklahoma working interest   |  |                                  | 75,181    |  |      |  | 84,066    |      |  |  | 86,099    | 
|                            |  |                                  |           |  |      |  |           |      |  |  |           | 
|Total                       |  |                                  | 197,102   |  |      |  | 219,480   |      |  |  | 224,296   | 
|                            |  |                                  |           |  |      |  |           |      |  |  |           | 



Nonproducing Acreage



The underlying nonproducing royalties contain approximately 240,000 gross (approximately 30,000 net) acres in Texas, Oklahoma and New Mexico which were nonproducing at the date of the trusts
creation. The trust



13



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##### Table of Contents

is entitled to 10% of oil and gas production attributable to the underlying mineral interests, but is not entitled to delay rental payments or lease bonuses. There has been no significant
development of such nonproducing acreage since the trusts creation.



Pricing and Sales Information



Oil and gas are generally sold from the underlying properties at market-sensitive prices. The majority of sales from the underlying working interest properties are to major oil and gas companies.
Information about purchasers of oil and gas from royalty properties is generally not provided by operators to XTO Energy as a royalty owner, or to the trust.



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. 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 Act of 1978, or FERC rules, regulations or orders thereunder. FERC has promulgated regulations to implement the Energy Policy Act, including enforcement rules and new annual reporting requirements for certain sellers of natural gas.
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.



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 crude oil, condensate or natural gas liquids 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.



14



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##### Table of Contents

There is an increased focus by local, national and international regulatory bodies on
greenhouse gas (GHG) emissions and climate change. Several states have adopted climate change legislation and regulations, and various other regulatory bodies have announced their intent to regulate GHG emissions or adopt climate change regulations.
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 the operators of the underlying properties could face
increases in operating costs in order to comply with climate change or 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 the
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.



In May 2006, the State of Texas modified its franchise tax to
impose a margin tax of up to 1% on revenues less certain costs, as specified in the legislation, generated from Texas activities beginning in 2007. Entities subject to the tax generally include trusts, unless otherwise exempt, and
various other types of entities. Trusts that meet statutory requirements are generally exempt from the margin tax as passive entities. The trust has been advised by Texas tax counsel that the trust is exempt from margin tax as a passive
entity. However, each unitholder that is a business entity or limited liability entity subject to the margin tax is generally required to include its share of the trusts revenues in its margin tax computation.



Unitholders are urged to consult their own tax advisors
regarding the requirements for filing state tax returns.



Other Regulation



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
|------- | -----------------



Certain of the underlying properties are involved in various 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. | [Removed and Reserved]
|------- | ----------------------



15



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##### Table of Contents

PART II



|Item 5. | Market for Units of the Trust, Related Unitholder Matters and Trust Purchases of Units
|------- | --------------------------------------------------------------------------------------



Units of Beneficial Interest



The units of beneficial interest in the trust are listed and
traded on the New York Stock Exchange under the symbol CRT. The following are the high and low unit sales prices and total cash distributions per unit paid by the trust during each quarter of 2010 and 2009:



|        |  |             |       |  |                       |   |       |  |  |   |          | 
|------- |  | ----------- | ----- |  | --------------------- | - | ----- |  |  | - | -------- | 
|        |  | Sales Price |       |  | Distributionsper Unit |  
|Quarter |  | High        |       |  | Low                   |   |      
|2010    |  |             |       |  |                       |   |       |  |  |   |          | 
|First   |  | $           | 35.00 |  |                       | $ | 28.21 |  |  | $ | 0.683096 | 
|Second  |  |             | 39.48 |  |                       |   | 31.00 |  |  |   | 0.747234 | 
|Third   |  |             | 36.92 |  |                       |   | 33.11 |  |  |   | 0.677215 | 
|Fourth  |  |             | 42.26 |  |                       |   | 35.14 |  |  |   | 0.680009 | 
|        |  |             |       |  |                       |   |       |  |  |   |          | 
|        |  |             |       |  |                       |   |       |  |  | $ | 2.787554 | 
|        |  |             |       |  |                       |   |       |  |  |   |          | 
|2009    |  |             |       |  |                       |   |       |  |  |   |          | 
|First   |  | $           | 35.27 |  |                       | $ | 13.92 |  |  | $ | 0.444965 | 
|Second  |  |             | 30.40 |  |                       |   | 17.28 |  |  |   | 0.381449 | 
|Third   |  |             | 31.45 |  |                       |   | 22.00 |  |  |   | 0.460847 | 
|Fourth  |  |             | 36.37 |  |                       |   | 28.20 |  |  |   | 0.598762 | 
|        |  |             |       |  |                       |   |       |  |  |   |          | 
|        |  |             |       |  |                       |   |       |  |  | $ | 1.886023 | 
|        |  |             |       |  |                       |   |       |  |  |   |          | 



At December 31, 2010, there were 6,000,000 units outstanding and approximately 330 unitholders of record; 5,812,729 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 31 |           
|                              |  | 2010                   |            |  | 2009 |   |            | 2008 |  |   | 2007       |  |  | 2006 |           
|Net Profits Income            |  | $                      | 17,142,087 |  |      | $ | 11,742,545 |      |  | $ | 31,311,215 |  |  | $    | 20,189,267 |  |  | $ | 25,767,154 | 
|Distributable Income          |  |                        | 16,725,324 |  |      |   | 11,316,138 |      |  |   | 30,942,420 |  |  |      | 19,805,724 |  |  |   | 25,448,178 | 
|Distributable Income per Unit |  |                        | 2.787554   |  |      |   | 1.886023   |      |  |   | 5.157070   |  |  |      | 3.300954   |  |  |   | 4.241363   | 
|Distributions per Unit        |  |                        | 2.787554   |  |      |   | 1.886023   |      |  |   | 5.157070   |  |  |      | 3.300954   |  |  |   | 4.241363   | 
|Total Assets at Year-End      |  |                        | 15,935,049 |  |      |   | 17,256,102 |      |  |   | 18,771,025 |  |  |      | 20,147,900 |  |  |   | 21,655,260 | 



16



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##### 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) |            |  | Quarter EndedDecember 31
(a) |  
|                                |  | 2010                       |            |  | 2009                         |   |            | 2008 |  |   | 2010       |  |  | 2009 |          
|Sales Volumes                   |  |                            |            |  |                              |   |            |      |  |   |            |  |  |      |           |  |  |   |           | 
|Oil (Bbls) (b)                  |  |                            |            |  |                              |   |            |      |  |   |            |  |  |      |           |  |  |   |           | 
|Underlying properties           |  |                            | 197,102    |  |                              |   | 219,480    |      |  |   | 224,296    |  |  |      | 48,399    |  |  |   | 53,041    | 
|Average per day                 |  |                            | 540        |  |                              |   | 601        |      |  |   | 613        |  |  |      | 526       |  |  |   | 577       | 
|Net profits interests           |  |                            | 99,628     |  |                              |   | 75,838     |      |  |   | 129,041    |  |  |      | 24,450    |  |  |   | 25,820    | 
|Gas (Mcf) (b)                   |  |                            |            |  |                              |   |            |      |  |   |            |  |  |      |           |  |  |   |           | 
|Underlying properties           |  |                            | 2,097,964  |  |                              |   | 2,026,608  |      |  |   | 2,079,350  |  |  |      | 549,311   |  |  |   | 542,708   | 
|Average per day                 |  |                            | 5,748      |  |                              |   | 5,552      |      |  |   | 5,681      |  |  |      | 5,971     |  |  |   | 5,899     | 
|Net profits interests           |  |                            | 1,836,889  |  |                              |   | 1,768,478  |      |  |   | 1,825,147  |  |  |      | 473,707   |  |  |   | 473,006   | 
|                                |  |                            |            |  |                             
|Average Sales Price             |  |                            |            |  |                              |   |            |      |  |   |            |  |  |      |           |  |  |   |           | 
|Oil (per Bbl)                   |  | $                          | 71.80      |  |                              | $ | 50.82      |      |  | $ | 99.68      |  |  | $    | 72.40     |  |  | $ | 65.39     | 
|Gas (per Mcf) (c)               |  | $                          | 7.06       |  |                              | $ | 5.58       |      |  | $ | 11.70      |  |  | $    | 6.57      |  |  | $ | 5.50      | 
|                                |  |                            |            |  |                             
|Revenues                        |  |                            |            |  |                              |   |            |      |  |   |            |  |  |      |           |  |  |   |           | 
|Oil sales                       |  | $                          | 14,152,470 |  |                              | $ | 11,154,802 |      |  | $ | 22,358,808 |  |  | $    | 3,503,971 |  |  | $ | 3,468,569 | 
|Gas sales (c)                   |  |                            | 14,813,040 |  |                              |   | 11,315,933 |      |  |   | 24,331,383 |  |  |      | 3,611,390 |  |  |   | 2,984,617 | 
|                                |  |                            |            |  |                              |   |            |      |  |   |            |  |  |      |           |  |  |   |           | 
|Total Revenues                  |  |                            | 28,965,510 |  |                              |   | 22,470,735 |      |  |   | 46,690,191 |  |  |      | 7,115,361 |  |  |   | 6,453,186 | 
|                                |  |                            |            |  |                              |   |            |      |  |   |            |  |  |      |           |  |  |   |           | 
|                                |  |                            |            |  |                             
|Costs                           |  |                            |            |  |                              |   |            |      |  |   |            |  |  |      |           |  |  |   |           | 
|Taxes, transportation and other |  |                            | 4,136,302  |  |                              |   | 3,495,414  |      |  |   | 5,357,997  |  |  |      | 959,866   |  |  |   | 981,324   | 
|Production expense (d)          |  |                            | 4,502,466  |  |                              |   | 5,092,484  |      |  |   | 4,603,581  |  |  |      | 1,114,907 |  |  |   | 1,146,971 | 
|Development costs               |  |                            | 539,048    |  |                              |   | 601,502    |      |  |   | 1,453,290  |  |  |      | 230,014   |  |  |   | 99,373    | 
|Excess costs (e)                |  |                            |           |  |                              |   | 6,995      |      |  |   |           |  |  |      |          |  |  |   |          | 
|                                |  |                            |            |  |                              |   |            |      |  |   |            |  |  |      |           |  |  |   |           | 
|Total Costs                     |  |                            | 9,177,816  |  |                              |   | 9,196,395  |      |  |   | 11,414,868 |  |  |      | 2,304,787 |  |  |   | 2,227,668 | 
|                                |  |                            |            |  |                              |   |            |      |  |   |            |  |  |      |           |  |  |   |           | 
|                                |  |                            |            |  |                             
|Other Proceeds                  |  |                            |            |  |                              |   |            |      |  |   |            |  |  |      |           |  |  |   |           | 
|Interest income (c)             |  |                            |           |  |                              |   |           |      |  |   | 1,024,815  |  |  |      |          |  |  |   |          | 
|                                |  |                            |            |  |                              |   |            |      |  |   |            |  |  |      |           |  |  |   |           | 
|Net Proceeds                    |  | $                          | 19,787,694 |  |                              | $ | 13,274,340 |      |  | $ | 36,300,138 |  |  | $    | 4,810,574 |  |  | $ | 4,225,518 | 
|                                |  |                            |            |  |                              |   |            |      |  |   |            |  |  |      |           |  |  |   |           | 
|Net Profits Income              |  | $                          | 17,142,087 |  |                              | $ | 11,742,545 |      |  | $ | 31,311,215 |  |  | $    | 4,130,924 |  |  | $ | 3,653,530 | 
|                                |  |                            |            |  |                              |   |            |      |  |   |            |  |  |      |           |  |  |   |           | 

---

|(a) | Because of the interval between time of production and receipt of net profits income by the trust, oil and gas sales for the year ended December 31 generally
relate to oil production from November through October and gas production from October through September, while oil and gas sales for the quarter ended December 31 generally relate to oil production from August through October and gas
production from July through September.
|--- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



|(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 analysis is based on the underlying properties.
|--- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



|(c) | In 2008, $2,430,326 was received related to lawsuit settlements for underpayment of royalties of $1,405,511 on certain San Juan Basin properties. Included in these
settlements was interest of $1,024,815. These settlements increased the average gas sale price by $0.67 for 2008. The total settlements, net to the trust, were $2,187,294, or $0.36 per unit.
|--- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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##### Table of Contents

|(d) | Production expense is primarily from seven working interest properties in the 75% net profits interest. Five of these properties are not operated by XTO Energy or
ExxonMobil. Production expense includes an overhead charge which is deducted and retained by the operator. As of December 31, 2010, this charge was $34,481 per month (including a monthly overhead charge of $2,713 which XTO Energy deducts as
operator of the Penwell Unit and $4,538 which ExxonMobil deducts as operator of the Hewitt Unit) and is subject to adjustment each May based on an oil and gas industry index.
|--- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



|(e) | See Note 8 to Financial Statements under Item 8, Financial Statements and Supplementary Data.
|--- | ---------------------------------------------------------------------------------------------



Results of Operations



Years Ended December 31, 2010, 2009 and 2008



Net profits income for 2010 was $17,142,087 as compared with
$11,742,545 for 2009 and $31,311,215 for 2008. The 46% increase in net profits income from 2009 to 2010 was primarily because of increased oil and gas prices ($6.3 million), increased gas production ($0.5 million) and decreased production expense
($0.4 million), partially offset by decreased oil production ($1.3 million) and higher taxes, transportation and other costs ($0.6 million). The 62% decrease in net profits income from 2008 to 2009 was primarily because of decreased oil and gas
prices ($18.9 million) and lawsuit settlement proceeds included in 2008 ($2.2 million), partially offset by lower taxes, transportation and other costs ($1.6 million) and lower development costs ($0.8 million). During 2010, 2009 and 2008, 60%, 65%
and 59%, respectively, of net profits income was derived from gas sales.



Trust administration expense was $417,063 in 2010 as compared to $426,630 in 2009 and $389,863 in 2008. Increased administrative expense from 2008 to 2009 is primarily due to the timing of expenditures.
Interest income was $300 in 2010, $223 in 2009 and $21,068 in 2008. Changes in interest income are attributable to fluctuations in net profits income and interest rates.



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 production and three months after 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



Oil. Underlying oil sales volumes decreased 10% from
2009 to 2010 compared to a 2% decrease from 2008 to 2009. Oil sales volumes in 2010 decreased from 2009 primarily because of natural production decline and the timing of cash receipts. Oil sales volumes in 2009 decreased from 2008 primarily because
of natural production decline and the timing of cash receipts, partially offset by prior period adjustments and increased production from new wells and workovers.



Gas. Underlying gas sales volumes increased 4% from
2009 to 2010 compared to a 3% decrease from 2008 to 2009. Gas sales volumes in 2010 increased from 2009 primarily because of the timing of cash receipts and increased production from new wells and workovers, partially offset by natural production
decline. Decreased gas sales volumes in 2009 were primarily because of prior period adjustments and natural production decline, partially offset by increased production from new wells and workovers and the timing of cash receipts.



The rate of natural production decline on the underlying oil
and gas properties is approximately 6% to 8% a year.



18



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##### Table of Contents

Prices



Oil. The average oil price for 2010 was $71.80 per
Bbl, 41% higher than the 2009 average oil price of $50.82, which was 49% lower than the 2008 average price of $99.68. Oil prices are expected to remain volatile. The average NYMEX price for November 2010 through January 2011 was $87.77 per Bbl. At
February 14, 2011, the average NYMEX oil price for the following 12 months was $95.00 per Bbl. Recent trust oil prices have averaged approximately 7% lower than the NYMEX price.



Gas. The 2010 average gas price was $7.06 per Mcf, a 27% increase from the 2009 average gas price of
$5.58, which was 52% lower than the 2008 average price of $11.70. Excluding the effects of the lawsuit settlements in 2008, the average gas price decreased 49% from $11.03 per Mcf in 2008 to $5.58 per Mcf in 2009. See Other Proceeds
below. Natural gas prices are affected by the level of North American production, weather, crude oil and natural gas liquids prices, the U.S. economy, storage levels and import levels of liquefied natural gas. Natural gas prices are expected to
remain volatile. The average NYMEX price for fourth quarter 2010 was $3.80 per MMBtu. Recent trust gas prices have averaged approximately 59% higher than the NYMEX price. At February 14, 2011, the average NYMEX gas price for the following 12
months was $4.31 per MMBtu.



Costs



Because properties underlying the 90% net profits interests
are royalty and overriding royalty interests, the calculation of net profits income from these interests only includes deductions for production and property taxes, legal costs, and marketing and transportation charges. In addition to these costs,
the calculation of net profits income from the 75% net profits interests includes deductions for production expense and development costs since the related underlying properties are working interests. Net profits income is calculated monthly for
each of the five conveyances under which the net profits interests were conveyed to the trust. If monthly 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 other conveyances. Costs have never exceeded revenues from 90% net profits interests, nor are they expected to in the future. Significantly lower oil prices and elevated costs caused costs to
exceed revenues by a total of $229,340 ($172,005 net to the trust) on properties underlying the Texas working interest for January through April 2009 and by $319,745 ($239,809 net to the trust) on properties underlying the Oklahoma working interest
for February through April 2009. However, these excess costs did not reduce net proceeds from the remaining conveyances. XTO Energy advised the trustee that increased oil prices and decreased costs led to the full recovery of excess costs, plus
accrued interest, during 2009. Interest paid on these excess costs totaled $6,995 ($5,246 net to the trust) in 2009. There were no excess costs in 2010.



Total costs deducted in the calculation of net profits income were $9.2 million in 2010, $9.2 million in 2009 and $11.4 million in 2008.
Total costs remained relatively flat from 2009 to 2010 as increased taxes, transportation and other costs due to higher oil and gas revenues were offset by decreased production expense related to decreased repairs and maintenance, overhead on
nonoperated properties and outside operated costs. The 19% decrease in costs from 2008 to 2009 is attributable to lower production taxes associated with decreased revenues and lower development costs, partially offset by increased production expense
related to increased overhead costs on nonoperated properties and increased carbon dioxide injection, repairs and maintenance costs and increased other deductions as a percentage of oil and gas revenues.



Unit operators of the properties underlying the 75% net
profits interests have reported total budgeted development costs, net to the underlying properties, of approximately $907,000 for 2011 and $881,000 for 2012, as compared to budgeted development costs of $585,000 and actual development costs of
$539,000 for 2010. Actual development costs often differ from amounts budgeted because of changes in product prices and other factors that may affect the timing or selection of projects.



19



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##### Table of Contents

Other Proceeds



The calculation of net profits income for 2008 includes
lawsuit settlements of $2,430,326 related to underpayment of royalties on underlying properties in the San Juan Basin. Included in these settlements was interest of $1,024,815 and additional gas revenue of $1,405,511, which increased the 2008
average gas sales price by $0.67 per Mcf. The total settlements, net to the trust, were $2,187,294, or $0.36 per unit.



State of Texas Margin Tax



In May 2006, the State of Texas modified its franchise tax to impose a margin tax of up to 1% on revenues less certain costs,
as specified in the legislation, generated from Texas activities beginning in 2007. Entities subject to the tax generally include trusts, unless otherwise exempt, and various other types of entities. Trusts that meet statutory requirements are
generally exempt from the margin tax as passive entities. The trust has been advised by Texas tax counsel that the trust is exempt from margin tax as a passive entity. However, each unitholder that is a business entity or limited
liability entity subject to the margin tax is generally required to include its share of the trusts revenues in its margin tax computation.



Unitholders are urged to consult their own tax advisors regarding the requirements for filing state tax returns.



Fourth Quarter 2010 and 2009



During the quarter ended December 31, 2010, the trust
received net profits income totaling $4,130,924, compared with fourth quarter 2009 net profits income of $3,653,530. This 13% increase is primarily attributable to higher oil and gas prices ($0.8 million), partially offset by decreased oil
production ($0.3 million).



Administration expense
was $50,985 and trust interest income was $115, resulting in fourth quarter 2010 distributable income of $4,080,054, or $0.680009 per unit. Distributable income for fourth quarter 2009 was $3,592,572, or $0.598762 per unit. Distributions to
unitholders for the quarter ended December 31, 2010 were:



|                  |  |                   |  |          |          | 
|----------------- |  | ----------------- |  | -------- | -------- | 
|Record Date       |  | Payment Date      |  | Per Unit |         
|October 29, 2010  |  | November 15, 2010 |  | $        | 0.254329 | 
|November 30, 2010 |  | December 14, 2010 |  |          | 0.190063 | 
|December 31, 2010 |  | January 14, 2011  |  |          | 0.235617 | 
|                  |  |                   |  |          |          | 
|                  |  |                   |  | $        | 0.680009 | 
|                  |  |                   |  |          |          | 



Volumes



Fourth quarter 2010 underlying oil sales volumes were 48,399 Bbls, or 9% lower than 2009 levels and underlying gas sales volumes were 549,311 Mcf, or 1% higher than 2009 levels. Oil sales volumes
decreased in 2010 primarily because of natural production decline and the timing of cash receipts. Gas sales volumes increased in 2010 primarily because of increased production from new wells and workovers and the timing of cash receipts, partially
offset by natural production decline.



Prices



The average fourth quarter 2010 oil
price was $72.40 per Bbl, 11% higher than the fourth quarter 2009 average price of $65.39. The average fourth quarter 2010 gas price was $6.57 per Mcf, 19% higher than the fourth quarter 2009 average price of $5.50. For further information about oil
and gas prices, see Years Ended December 31, 2010, 2009 and 2008  Prices above.



20



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##### Table of Contents

Costs



Costs deducted in the calculation of fourth quarter 2010 net
profits income increased $77,119, or 3%, from fourth quarter 2009. This increase was primarily related to higher development costs due to increased activity and costs related to the Texas and Oklahoma properties underlying the 75% net profits
interests.



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 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 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 Regulations



There is an increased focus by local, national and international regulatory bodies on greenhouse gas (GHG) emissions and climate change.
Several states have adopted climate change legislation and regulations, and various other regulatory bodies have announced their intent to regulate GHG emissions or adopt climate change regulations. 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 the operators of the underlying properties could face increases in operating costs in order to comply
with climate change or 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, 2010, other than
the December distribution payable to unitholders in January 2011, as shown in the statement of assets, liabilities and trust corpus.



|                                    |  |                        |           |  |                 |   |           |            |  |   |            |  |  |                  |   |  |  |   |   | 
|----------------------------------- |  | ---------------------- | --------- |  | --------------- | - | --------- | ---------- |  | - | ---------- |  |  | ---------------- | - |  |  | - | - | 
|                                    |  | Payments due by Period |          
|                                    |  | Total                  |           |  | Less than1 Year |   |           | 1 -3 Years |  |   | 3 -5 Years |  |  | More than5
Years |  
|Distribution payable to unitholders |  | $                      | 1,413,702 |  |                 | $ | 1,413,702 |            |  | $ |           |  |  | $                |  |  |  | $ |  | 



Related Party Transactions



The underlying properties are currently owned by XTO Energy. XTO Energy deducts an overhead charge from monthly net proceeds as reimbursement for costs associated with monitoring the 75% net profits
interests. As of December 31, 2010, this monthly charge was $34,481 ($25,861 net to the trust). Included in this monthly overhead charge is a charge XTO Energy deducts as operator of the Penwell Unit and ExxonMobil deducts as operator of the
Hewitt Unit. As of December 31, 2010, monthly overhead attributable to the Penwell Unit was $2,713 ($2,035 net to the trust) and monthly overhead attributable to the Hewitt Unit was $4,538 ($3,404 net to



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the trust). These overhead charges are subject to annual adjustment based on an oil and gas industry index. For further information regarding the trusts relationship with XTO Energy, see
Note 5 to Financial Statements under Item 8, Financial Statements and Supplementary Data.



On June 25, 2010, XTO Energy became a wholly owned subsidiary of Exxon Mobil Corporation. The merger is not expected to have a material effect on trust annual distributable income, financial position
or liquidity.



Critical Accounting Policies



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



Basis of Accounting



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



| |  |  | Net profits income is recognized in the month received rather than accrued in the month of production.
| | - |  | ------------------------------------------------------------------------------------------------------

| |  |  | Expenses are recognized when paid rather than when incurred.
| | - |  | ------------------------------------------------------------

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



This comprehensive
basis of accounting other than U.S. generally accepted accounting principles corresponds to the accounting permitted for royalty trusts by the U.S. Securities and Exchange Commission, as specified by Staff Accounting Bulletin Topic 12:E, Financial
Statements of Royalty Trusts. For further information regarding the trusts basis of accounting, see Note 2 to Financial Statements 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 using 12-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 2010 and 2009, and year end costs for estimated



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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,
development activities, future development plans, increased density drilling, reserve-to-production ratios, future net cash flows, maintenance projects, development, production and other costs, oil and gas prices, pricing differentials, proved
reserves, production levels, litigation, regulatory matters and competition. Such forward-looking statements are based on XTO Energys current plans, expectations, assumptions, projections and estimates and are identified by words such as
expects, intends, plans, projects, anticipates, predicts, believes, goals, estimates, should, could, and similar
words that convey the uncertainty of future events. These statements are not guarantees of future performance and involve certain risks, uncertainties and assumptions that are difficult to predict. Therefore, actual results may differ materially
from expectations, estimates or assumptions expressed in, implied in, or forecasted in such forward-looking statements. Some of the risk factors that could cause actual results to differ materially are explained in Item 1A, 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
|------- | -------------------------------------------



|                                                        |  |      |    | 
|------------------------------------------------------- |  | ---- | -- | 
|                                                        |  | Page |   
|Statements of Assets, Liabilities and Trust Corpus      |  |      | 24 | 
|Statements of Distributable Income                      |  |      | 25 | 
|Statements of Changes in Trust Corpus                   |  |      | 26 | 
|Notes to Financial Statements                           |  |      | 27 | 
|Report of Independent Registered Public Accounting Firm |  |      | 34 | 



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.



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Cross Timbers Royalty Trust



Statements of Assets, Liabilities and Trust Corpus



|                                                                                 |  |             |            |  |      |   |            | 
|-------------------------------------------------------------------------------- |  | ----------- | ---------- |  | ---- | - | ---------- | 
|                                                                                 |  | December 31 |           
|                                                                                 |  | 2010        |            |  | 2009 |  
|Assets                                                                           |  |             |            |  |      |   |            | 
|Cash and short-term investments                                                  |  | $           | 1,413,665  |  |      | $ | 1,067,595  | 
|Interest to be received                                                          |  |             | 37         |  |      |   | 9          | 
|Net profits interests in oil and gas propertiesnet (Notes 1 and 2)              |  |             | 14,521,347 |  |      |   | 16,188,498 | 
|                                                                                 |  |             |            |  |      |   |            | 
|                                                                                 |  | $           | 15,935,049 |  |      | $ | 17,256,102 | 
|                                                                                 |  |             |            |  |      |   |            | 
|                                                                                 |  |            
|Liabilities and Trust Corpus                                                     |  |             |            |  |      |   |            | 
|Distribution payable to unitholders                                              |  | $           | 1,413,702  |  |      | $ | 1,067,604  | 
|Trust corpus (6,000,000 units of beneficial interest authorized and outstanding) |  |             | 14,521,347 |  |      |   | 16,188,498 | 
|                                                                                 |  |             |            |  |      |   |            | 
|                                                                                 |  | $           | 15,935,049 |  |      | $ | 17,256,102 | 
|                                                                                 |  |             |            |  |      |   |            | 



See accompanying notes to financial statements.



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Cross Timbers Royalty Trust



Statements of Distributable Income



|                                                |  |                        |            |  |      |   |            |      |  |   |            | 
|----------------------------------------------- |  | ---------------------- | ---------- |  | ---- | - | ---------- | ---- |  | - | ---------- | 
|                                                |  | Year Ended December 31 |           
|                                                |  | 2010                   |            |  | 2009 |   |            | 2008 | 
|Net profits income                              |  | $                      | 17,142,087 |  |      | $ | 11,742,545 |      |  | $ | 31,311,215 | 
|Interest income                                 |  |                        | 300        |  |      |   | 223        |      |  |   | 21,068     | 
|                                                |  |                        |            |  |      |   |            |      |  |   |            | 
|Total income                                    |  |                        | 17,142,387 |  |      |   | 11,742,768 |      |  |   | 31,332,283 | 
|Administration expense                          |  |                        | 417,063    |  |      |   | 426,630    |      |  |   | 389,863    | 
|                                                |  |                        |            |  |      |   |            |      |  |   |            | 
|Distributable income                            |  | $                      | 16,725,324 |  |      | $ | 11,316,138 |      |  | $ | 30,942,420 | 
|                                                |  |                        |            |  |      |   |            |      |  |   |            | 
|Distributable income per unit (6,000,000 units) |  | $                      | 2.787554   |  |      | $ | 1.886023   |      |  | $ | 5.157070   | 
|                                                |  |                        |            |  |      |   |            |      |  |   |            | 



See accompanying notes to financial statements.



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Cross Timbers Royalty Trust



Statements of Changes in Trust Corpus



|                                      |  |                        |             |   |      |   |             |      |  |   |             |  
|------------------------------------- |  | ---------------------- | ----------- | - | ---- | - | ----------- | ---- |  | - | ----------- | -
|                                      |  | Year Ended December 31 |            
|                                      |  | 2010                   |             |   | 2009 |   |             | 2008 | 
|Trust corpus, beginning of year       |  | $                      | 16,188,498  |   |      | $ | 17,255,761  |      |  | $ | 18,387,752  |  
|Amortization of net profits interests |  |                        | (1,667,151  | ) |      |   | (1,067,263  | )    |  |   | (1,131,991  | )
|Distributable income                  |  |                        | 16,725,324  |   |      |   | 11,316,138  |      |  |   | 30,942,420  |  
|Distributions declared                |  |                        | (16,725,324 | ) |      |   | (11,316,138 | )    |  |   | (30,942,420 | )
|                                      |  |                        |             |   |      |   |             |      |  |   |             |  
|Trust corpus, end of year             |  | $                      | 14,521,347  |   |      | $ | 16,188,498  |      |  | $ | 17,255,761  |  
|                                      |  |                        |             |   |      |   |             |      |  |   |             |  



See accompanying notes to financial statements.



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CROSS TIMBERS ROYALTY TRUST



NOTES TO FINANCIAL STATEMENTS



1. Trust Organization and Provisions



Cross Timbers Royalty Trust was created on February 12,
1991 by predecessors of XTO Energy Inc., when the following net profits interests were conveyed under five separate conveyances to the trust effective October 1, 1990, in exchange for 6,000,000 units of beneficial interest in the trust:



| |  | 90% net profits interests in certain producing and nonproducing royalty and overriding royalty interest properties in Texas, Oklahoma and New Mexico, and
| | - | ---------------------------------------------------------------------------------------------------------------------------------------------------------



| |  | 75% net profits interests in certain nonoperated working interest properties in Texas and Oklahoma.
| | - | ---------------------------------------------------------------------------------------------------



The underlying properties from which the net profits
interests were carved are currently owned by XTO Energy (Note 5). The trusts initial public offering was in February 1992.



Bank of America, N.A. is 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 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 may not engage in any business activity or acquire any assets other than the net profits interests and specific short-term cash investments;
| | - | ------------------------------------------------------------------------------------------------------------------------------------------------------



| |  | the trust may not dispose of all or part of the net profits interests unless approved by 80% of the unitholders, or upon trust termination, and 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 required to pay trust liabilities if fully repaid 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 revenue of the trust is less than $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).
| | - | -----------------------------------------------------------------------------



| |  | Interest income, interest to be received and distribution payable to unitholders include interest to be earned on net profits income from the monthly record date (last
business day of the month) through the date of the next distribution.
| | - | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  | 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).
| | - | --------------------------------------------------------------------------------



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



| |  | Net profits income is recognized in the month received rather than accrued in the month of production.
| | - | ------------------------------------------------------------------------------------------------------



| |  | Expenses are recognized when paid rather than when incurred.
| | - | ------------------------------------------------------------



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



This comprehensive basis of
accounting 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.



The initial carrying value of the net profits interests of
$61,100,449 was XTO Energys historical net book value of the interests on February 12, 1991, 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 $46,579,102 as of December 31, 2010 and $44,911,951 as of December 31, 2009.



3. Distributions to Unitholders



The trustee determines the amount to be distributed to unitholders each month by totaling net profits income and other cash receipts, and
subtracting liabilities paid and adjustments in cash reserves established by the trustee. The resulting amount (with estimated interest to be received on such amount through the distribution date) is distributed to unitholders of record within ten
business days after the monthly record date, 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 the net profits percentage of 90% or 75%. Net
proceeds are the gross proceeds received from the sale of production, less applicable costs. For the 90% net profits interests, such costs generally include production and property taxes, legal costs, and marketing and transportation charges. In
addition to these costs, the 75% net profits interests include deductions for production expense and development costs.



XTO Energy, as owner of the underlying properties, computes net profits income separately for each of the five conveyances. If costs
exceed gross proceeds 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 8).



4. 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.



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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.



5. XTO Energy Inc.



The underlying properties include approximately 20 overriding royalty interests in New Mexico that burden working interests owned and operated by XTO Energy. These working interests were purchased by XTO
Energy after the net profits interests were conveyed to the trust. XTO Energy also operates the Penwell Unit, which is one of the properties underlying the Texas 75% net profits interests and ExxonMobil operates the Hewitt Unit, which is one of the
properties underlying the Oklahoma 75% net profits interests. Other than these properties, XTO Energy and ExxonMobil do not operate or control any of the underlying properties or related working interests.



In computing net profits income for the 75% net profits
interests (Note 3), XTO Energy deducts an overhead charge as reimbursement for costs associated with monitoring these interests. This charge at December 31, 2010 was $34,481 per month, or $413,772 annually (net to the trust of $310,329
annually). Included in this monthly overhead charge is a charge XTO Energy deducts as operator of the Penwell Unit and ExxonMobil deducts as operator of the Hewitt Unit. As of December 31, 2010, overhead attributable to the Penwell Unit was
$2,713 per month, or $32,556 annually (net to the trust of $24,417 annually) and overhead attributable to the Hewitt Unit was $4,538 per month, or $54,456 annually (net to the trust of $40,842 annually). These overhead charges are subject to an
annual adjustment based on an oil and gas industry index.



On June 25, 2010, XTO Energy became a wholly owned subsidiary of Exxon Mobil Corporation. The merger is not expected to have a material effect on trust annual distributable income, financial position
or liquidity.



6. Contingencies



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 the 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.



7. Purchaser Adjustments and Lawsuit Settlements



From time-to-time, XTO Energy receives net proceeds for the underlying properties related to significant prior period purchaser
adjustments and lawsuit settlements, including related interest income. Because of the size and nature of these adjustments and settlements, XTO Energy has informed the trustee that it believes these should be considered one-time, or nonrecurring,
events. Since most of the properties in the trust are nonoperated, these adjustments are generally not known to XTO Energy until reported by the purchaser. These items are included and reported in net profits income in the month received by the
trust, which is generally the month following receipt by XTO Energy.



In 2008, the calculation of net profits income includes proceeds from lawsuit settlements of $2,430,326 related to underpayment of royalties on underlying properties in the San Juan Basin. Included in
these settlements was interest of $1,024,815 and additional gas revenue of $1,405,511. The total settlements, net to the trust, were $2,187,294, or $0.36 per unit.



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8. Excess Costs



Significantly lower oil prices and elevated costs caused
costs to exceed revenues by a total of $229,340 ($172,005 net to the trust) on properties underlying the Texas working interest for January through April 2009 and by $319,745 ($239,809 net to the trust) on properties underlying the Oklahoma working
interest for February through April 2009. However, these costs did not reduce net proceeds from the remaining conveyances. XTO Energy advised the trustee that increased oil prices and decreased costs led to the full recovery of excess costs, plus
accrued interest, during 2009. Interest paid on these excess costs totaled $6,995 ($5,246 net to the trust) in 2009. There were no excess costs in 2010.



9. Supplemental Oil and Gas Reserve Information (Unaudited)



Oil and Natural Gas Reserves



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 2010 and 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 affected by recent economic
conditions as well as other factors and may not be the most representative in estimating future revenues or reserve data.



Oil prices used to determine the standardized measure were based on average realized oil prices of $73.20 per Bbl in 2010, $53.92 per Bbl
in 2009, $36.46 per Bbl in 2008 and $88.11 per Bbl in 2007. The weighted average realized gas prices used to determine the standardized measure were $5.42 per Mcf in 2010, $4.07 per Mcf in 2009, $4.27 per Mcf in 2008 and $6.41 per Mcf in 2007. In
2010 and 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.



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Proved Reserves



|                                      |  |                          |     |   |                          |  |        |           |  |  |          |   |  |           |      |   |          |  |       |           |  |  |          |   |  |  |       |   |  |  |        |  
|------------------------------------- |  | ------------------------ | --- | - | ------------------------ |  | ------ | --------- |  |  | -------- | - |  | --------- | ---- | - | -------- |  | ----- | --------- |  |  | -------- | - |  |  | ----- | - |  |  | ------ | -
|                                      |  | Net Profits Interests    |     |   | UnderlyingProperties     | 
|                                      |  | 90% NetProfits
Interests |     |   | 75%
NetProfits Interests |  |        | Total     |  | 
|(in thousands)                        |  | Oil(Bbls)                |     |   | Gas(Mcf)                 |  |        | Oil(Bbls) |  |  | Gas(Mcf) |   |  | Oil(Bbls) |      |   | Gas(Mcf) |  |       | Oil(Bbls) |  |  | Gas(Mcf) |  
|Balance, December 31, 2007            |  |                          | 505 |   |                          |  | 27,202 |           |  |  | 1,232    |   |  |           | 457  |   |          |  | 1,737 |           |  |  | 27,659   |   |  |  | 3,106 |   |  |  | 31,202 |  
|Extensions, additions and discoveries |  |                          | 9   |   |                          |  | 915    |           |  |  |         |   |  |           |     |   |          |  | 9     |           |  |  | 915      |   |  |  | 10    |   |  |  | 1,016  |  
|Revisions of prior estimates          |  |                          | 78  |   |                          |  | (854   | )         |  |  | (846     | ) |  |           | (337 | ) |          |  | (768  | )         |  |  | (1,191   | ) |  |  | (773  | ) |  |  | (1,303 | )
|Production                            |  |                          | (60 | ) |                          |  | (1,800 | )         |  |  | (69      | ) |  |           | (25  | ) |          |  | (129  | )         |  |  | (1,825   | ) |  |  | (224  | ) |  |  | (2,079 | )
|                                      |  |                          |     |   |                          |  |        |           |  |  |          |   |  |           |      |   |          |  |       |           |  |  |          |   |  |  |       |   |  |  |        |  
|Balance, December 31, 2008            |  |                          | 532 |   |                          |  | 25,463 |           |  |  | 317      |   |  |           | 95   |   |          |  | 849   |           |  |  | 25,558   |   |  |  | 2,119 |   |  |  | 28,836 |  
|Extensions, additions and discoveries |  |                          | 9   |   |                          |  | 1,240  |           |  |  |         |   |  |           |     |   |          |  | 9     |           |  |  | 1,240    |   |  |  | 10    |   |  |  | 1,379  |  
|Revisions of prior estimates          |  |                          | 21  |   |                          |  | 639    |           |  |  | 53       |   |  |           | 9    |   |          |  | 74    |           |  |  | 648      |   |  |  | 282   |   |  |  | 777    |  
|Production                            |  |                          | (59 | ) |                          |  | (1,761 | )         |  |  | (17      | ) |  |           | (7   | ) |          |  | (76   | )         |  |  | (1,768   | ) |  |  | (219  | ) |  |  | (2,027 | )
|                                      |  |                          |     |   |                          |  |        |           |  |  |          |   |  |           |      |   |          |  |       |           |  |  |          |   |  |  |       |   |  |  |        |  
|Balance, December 31, 2009            |  |                          | 503 |   |                          |  | 25,581 |           |  |  | 353      |   |  |           | 97   |   |          |  | 856   |           |  |  | 25,678   |   |  |  | 2,192 |   |  |  | 28,965 |  
|                                      |  |                          |     |   |                          |  |        |           |  |  |          |   |  |           |      |   |          |  |       |           |  |  |          |   |  |  |       |   |  |  |        |  
|Extensions, additions and discoveries |  |                          | 5   |   |                          |  | 594    |           |  |  |         |   |  |           |     |   |          |  | 5     |           |  |  | 594      |   |  |  | 6     |   |  |  | 659    |  
|Revisions of prior estimates          |  |                          | 46  |   |                          |  | 413    |           |  |  | 257      |   |  |           | 69   |   |          |  | 303   |           |  |  | 482      |   |  |  | 303   |   |  |  | 546    |  
|Production                            |  |                          | (51 | ) |                          |  | (1,822 | )         |  |  | (49      | ) |  |           | (15  | ) |          |  | (100  | )         |  |  | (1,837   | ) |  |  | (197  | ) |  |  | (2,098 | )
|                                      |  |                          |     |   |                          |  |        |           |  |  |          |   |  |           |      |   |          |  |       |           |  |  |          |   |  |  |       |   |  |  |        |  
|Balance, December 31, 2010            |  |                          | 503 |   |                          |  | 24,766 |           |  |  | 561      |   |  |           | 151  |   |          |  | 1,064 |           |  |  | 24,917   |   |  |  | 2,304 |   |  |  | 28,072 |  
|                                      |  |                          |     |   |                          |  |        |           |  |  |          |   |  |           |      |   |          |  |       |           |  |  |          |   |  |  |       |   |  |  |        |  



Extensions, additions and discoveries of proved gas reserves are primarily because of development in the San Juan Basin. Revisions of prior estimates are primarily related to changes in prices and costs.



Proved Developed Reserves



|                  |  |                          |     |  |                          |  |        |           |  |  |          |  |  |           |     |  |          |  |       |           |  |  |          |  |  |  |       |  |  |  |        | 
|----------------- |  | ------------------------ | --- |  | ------------------------ |  | ------ | --------- |  |  | -------- |  |  | --------- | --- |  | -------- |  | ----- | --------- |  |  | -------- |  |  |  | ----- |  |  |  | ------ | 
|                  |  | Net Profits Interests    |     |  | UnderlyingProperties     | 
|                  |  | 90% NetProfits
Interests |     |  | 75%
NetProfits Interests |  |        | Total     |  | 
|(in thousands)    |  | Oil(Bbls)                |     |  | Gas(Mcf)                 |  |        | Oil(Bbls) |  |  | Gas(Mcf) |  |  | Oil(Bbls) |     |  | Gas(Mcf) |  |       | Oil(Bbls) |  |  | Gas(Mcf) | 
|December 31, 2007 |  |                          | 505 |  |                          |  | 27,202 |           |  |  | 1,229    |  |  |           | 450 |  |          |  | 1,734 |           |  |  | 27,652   |  |  |  | 3,098 |  |  |  | 31,186 | 
|                  |  |                          |     |  |                          |  |        |           |  |  |          |  |  |           |     |  |          |  |       |           |  |  |          |  |  |  |       |  |  |  |        | 
|December 31, 2008 |  |                          | 532 |  |                          |  | 25,463 |           |  |  | 316      |  |  |           | 93  |  |          |  | 848   |           |  |  | 25,556   |  |  |  | 2,114 |  |  |  | 28,825 | 
|                  |  |                          |     |  |                          |  |        |           |  |  |          |  |  |           |     |  |          |  |       |           |  |  |          |  |  |  |       |  |  |  |        | 
|December 31, 2009 |  |                          | 503 |  |                          |  | 25,581 |           |  |  | 353      |  |  |           | 97  |  |          |  | 856   |           |  |  | 25,678   |  |  |  | 2,192 |  |  |  | 28,965 | 
|                  |  |                          |     |  |                          |  |        |           |  |  |          |  |  |           |     |  |          |  |       |           |  |  |          |  |  |  |       |  |  |  |        | 
|December 31, 2010 |  |                          | 503 |  |                          |  | 24,766 |           |  |  | 561      |  |  |           | 151 |  |          |  | 1,064 |           |  |  | 24,917   |  |  |  | 2,304 |  |  |  | 28,072 | 
|                  |  |                          |     |  |                          |  |        |           |  |  |          |  |  |           |     |  |          |  |       |           |  |  |          |  |  |  |       |  |  |  |        | 



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Standardized Measure of Discounted Future Net Cash Flows from Proved Reserves



|                        |  |                           |         |          |                           |   |         |             |   |   |         |         |   |      |         |   |      |   |        |      |  |   |        |   |  |      |         |   |  |   |         |   |  |   |         |  
|----------------------- |  | ------------------------- | ------- | -------- | ------------------------- | - | ------- | ----------- | - | - | ------- | ------- | - | ---- | ------- | - | ---- | - | ------ | ---- |  | - | ------ | - |  | ---- | ------- | - |  | - | ------- | - |  | - | ------- | -
|                        |  | 90% Net Profits Interests |         |          | 75% Net Profits Interests |   |         | Total       |  
|                        |  | December 31               |         |          | December 31               |   |         | December 31 |  
|(in thousands)          |  | 2010                      |         |          | 2009                      |   |         | 2008        |   |   | 2010    |         |   | 2009 |         |   | 2008 |   |        | 2010 |  |   | 2009   |   |  | 2008 |        
|Net Profits Interests   |  |                           |         |          |                           |   |         |             |   |   |         |         |   |      |         |   |      |   |        |      |  |   |        |   |  |      |         |   |  |   |         |   |  |   |         |  
|Future cash inflows     |  | $                         | 172,407 |          |                           | $ | 133,186 |             |   | $ | 128,401 |         |   | $    | 41,539  |   |      | $ | 19,266 |      |  | $ | 11,759 |   |  | $    | 213,946 |   |  | $ | 152,452 |   |  | $ | 140,160 |  
|Future production taxes |  |                           | (13,562 | )        |                           |   | (10,722 | )           |   |   | (10,681 | )       |   |      | (2,590  | ) |      |   | (1,179 | )    |  |   | (736   | ) |  |      | (16,152 | ) |  |   | (11,901 | ) |  |   | (11,417 | )
|                        |  |                           |         |          |                           |   |         |             |   |   |         |         |   |      |         |   |      |   |        |      |  |   |        |   |  |      |         |   |  |   |         |   |  |   |         |  
|Future net cash flows   |  |                           | 158,845 |          |                           |   | 122,464 |             |   |   | 117,720 |         |   |      | 38,949  |   |      |   | 18,087 |      |  |   | 11,023 |   |  |      | 197,794 |   |  |   | 140,551 |   |  |   | 128,743 |  
|10% discount factor     |  |                           | (81,698 | )        |                           |   | (62,521 | )           |   |   | (60,109 | )       |   |      | (17,973 | ) |      |   | (7,004 | )    |  |   | (4,161 | ) |  |      | (99,671 | ) |  |   | (69,525 | ) |  |   | (64,270 | )
|                        |  |                           |         |          |                           |   |         |             |   |   |         |         |   |      |         |   |      |   |        |      |  |   |        |   |  |      |         |   |  |   |         |   |  |   |         |  
|Standardized measure    |  | $                         | 77,147  |          |                           | $ | 59,943  |             |   | $ | 57,611  |         |   | $    | 20,976  |   |      | $ | 11,083 |      |  | $ | 6,862  |   |  | $    | 98,123  |   |  | $ | 71,026  |   |  | $ | 64,473  |  
|                        |  |                           |         |          |                           |   |         |             |   |   |         |         |   |      |         |   |      |   |        |      |  |   |        |   |  |      |         |   |  |   |         |   |  |   |         |  
|                        |  |                           |         |          |                           |   |         |             |  
|Underlying Properties   |  |                           |         |          |                           |   |         |             |   |   |         |         |   |      |         |   |      |   |        |      |  |   |        |   |  |      |         |   |  |   |         |   |  |   |         |  
|Future cash inflows     |  |                           | $       | 320,767  |                           |   | $       | 236,719     |   |   | $       | 199,671 |  
|Future production costs |  |                           |         | (92,341  | )                         |   |         | (76,532     | ) |   |         | (54,174 | )
|                        |  |                           |         |          |                           |   |         |             |   |   |         |         |   |      |         |   |      |   |        |      |  |   |        |   |  |      |         |   |  |   |         |   |  |   |         |  
|Future net cash flows   |  |                           |         | 228,426  |                           |   |         | 160,187     |   |   |         | 145,497 |  
|10% discount factor     |  |                           |         | (114,739 | )                         |   |         | (78,807     | ) |   |         | (72,335 | )
|                        |  |                           |         |          |                           |   |         |             |   |   |         |         |   |      |         |   |      |   |        |      |  |   |        |   |  |      |         |   |  |   |         |   |  |   |         |  
|Standardized measure    |  |                           | $       | 113,687  |                           |   | $       | 81,380      |   |   | $       | 73,162  |  
|                        |  |                           |         |          |                           |   |         |             |   |   |         |         |   |      |         |   |      |   |        |      |  |   |        |   |  |      |         |   |  |   |         |   |  |   |         |  



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



|                                                         |  |                           |         |         |                           |   |         |         |   |   |         |         |   |      |        |   |      |   |        |      |  |   |         |   |  |      |         |   |  |   |         |   |  |   |         |  
|-------------------------------------------------------- |  | ------------------------- | ------- | ------- | ------------------------- | - | ------- | ------- | - | - | ------- | ------- | - | ---- | ------ | - | ---- | - | ------ | ---- |  | - | ------- | - |  | ---- | ------- | - |  | - | ------- | - |  | - | ------- | -
|                                                         |  | 90% Net Profits Interests |         |         | 75% Net Profits Interests |   |         | Total   |  
|(in thousands)                                           |  | 2010                      |         |         | 2009                      |   |         | 2008    |   |   | 2010    |         |   | 2009 |        |   | 2008 |   |        | 2010 |  |   | 2009    |   |  | 2008 |        
|Net Profits Interests                                    |  |                           |         |         |                           |   |         |         |   |   |         |         |   |      |        |   |      |   |        |      |  |   |         |   |  |      |         |   |  |   |         |   |  |   |         |  
|Standardized measure, January 1                          |  | $                         | 59,943  |         |                           | $ | 57,611  |         |   | $ | 96,533  |         |   | $    | 11,083 |   |      | $ | 6,862  |      |  | $ | 48,768  |   |  | $    | 71,026  |   |  | $ | 64,473  |   |  | $ | 145,301 |  
|Extensions, additions and discoveries                    |  |                           | 1,866   |         |                           |   | 2,669   |         |   |   | 1,918   |         |   |      |       |   |      |   |       |      |  |   |        |   |  |      | 1,866   |   |  |   | 2,669   |   |  |   | 1,918   |  
|Accretion of discount                                    |  |                           | 5,063   |         |                           |   | 4,859   |         |   |   | 8,087   |         |   |      | 994    |   |      |   | 625    |      |  |   | 4,174   |   |  |      | 6,057   |   |  |   | 5,484   |   |  |   | 12,261  |  
|Revisions of prior estimates, changes in price and other |  |                           | 24,083  |         |                           |   | 5,524   |         |   |   | (25,333 | )       |   |      | 12,233 |   |      |   | 4,618  |      |  |   | (39,285 | ) |  |      | 36,316  |   |  |   | 10,142  |   |  |   | (64,618 | )
|Net profits income                                       |  |                           | (13,808 | )       |                           |   | (10,720 | )       |   |   | (23,594 | )       |   |      | (3,334 | ) |      |   | (1,022 | )    |  |   | (6,795  | ) |  |      | (17,142 | ) |  |   | (11,742 | ) |  |   | (30,389 | )
|                                                         |  |                           |         |         |                           |   |         |         |   |   |         |         |   |      |        |   |      |   |        |      |  |   |         |   |  |      |         |   |  |   |         |   |  |   |         |  
|Standardized measure, December 31                        |  | $                         | 77,147  |         |                           | $ | 59,943  |         |   | $ | 57,611  |         |   | $    | 20,976 |   |      | $ | 11,083 |      |  | $ | 6,862   |   |  | $    | 98,123  |   |  | $ | 71,026  |   |  | $ | 64,473  |  
|                                                         |  |                           |         |         |                           |   |         |         |   |   |         |         |   |      |        |   |      |   |        |      |  |   |         |   |  |      |         |   |  |   |         |   |  |   |         |  
|                                                         |  |                           |         |         |                           |   |         |         |  
|Underlying Properties                                    |  |                           |         |         |                           |   |         |         |   |   |         |         |   |      |        |   |      |   |        |      |  |   |         |   |  |      |         |   |  |   |         |   |  |   |         |  
|Standardized measure, January 1                          |  |                           | $       | 81,380  |                           |   | $       | 73,162  |   |   | $       | 172,283 |  
|                                                         |  |                           |         |         |                           |   |         |         |   |   |         |         |   |      |        |   |      |   |        |      |  |   |         |   |  |      |         |   |  |   |         |   |  |   |         |  
|Revisions:                                               |  |                           |         |         |                           |   |         |         |   |   |         |         |  
|Prices and costs                                         |  |                           |         | 42,425  |                           |   |         | 9,180   |   |   |         | (69,652 | )
|Quantity estimates                                       |  |                           |         | 1,196   |                           |   |         | 3,678   |   |   |         | (9,421  | )
|Accretion of discount                                    |  |                           |         | 6,951   |                           |   |         | 6,232   |   |   |         | 14,551  |  
|Future development costs                                 |  |                           |         | (539    | )                         |   |         | (587    | ) |   |         | (1,451  | )
|Other                                                    |  |                           |         | (12     | )                         |   |         | (3      | ) |   |         | (4      | )
|                                                         |  |                           |         |         |                           |   |         |         |   |   |         |         |   |      |        |   |      |   |        |      |  |   |         |   |  |      |         |   |  |   |         |   |  |   |         |  
|Net revisions                                            |  |                           |         | 50,021  |                           |   |         | 18,500  |   |   |         | (65,977 | )
|Extensions, additions and discoveries                    |  |                           |         | 2,074   |                           |   |         | 2,999   |   |   |         | 2,132   |  
|Production                                               |  |                           |         | (20,327 | )                         |   |         | (13,883 | ) |   |         | (36,729 | )
|Development costs                                        |  |                           |         | 539     |                           |   |         | 602     |   |   |         | 1,453   |  
|                                                         |  |                           |         |         |                           |   |         |         |   |   |         |         |   |      |        |   |      |   |        |      |  |   |         |   |  |      |         |   |  |   |         |   |  |   |         |  
|Net change                                               |  |                           |         | 32,307  |                           |   |         | 8,218   |   |   |         | (99,121 | )
|                                                         |  |                           |         |         |                           |   |         |         |   |   |         |         |   |      |        |   |      |   |        |      |  |   |         |   |  |      |         |   |  |   |         |   |  |   |         |  
|Standardized measure, December 31                        |  |                           | $       | 113,687 |                           |   | $       | 81,380  |   |   | $       | 73,162  |  
|                                                         |  |                           |         |         |                           |   |         |         |   |   |         |         |   |      |        |   |      |   |        |      |  |   |         |   |  |      |         |   |  |   |         |   |  |   |         |  



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11. Quarterly Financial Data (Unaudited)



The following is a summary of net profits income, distributable income and distributable income per unit by
quarter for 2010 and 2009:



|               |  |                   |            |  |                     |   |            |                             |  |   |          | 
|-------------- |  | ----------------- | ---------- |  | ------------------- | - | ---------- | --------------------------- |  | - | -------- | 
|               |  | Net
ProfitsIncome |            |  | DistributableIncome |   |            | DistributableIncomeper Unit | 
|               |  |                   |           
|2010           |  |                   |            |  |                     |   |            |                             |  |   |          | 
|               |  |                   |           
|First Quarter  |  | $                 | 4,269,080  |  |                     | $ | 4,098,576  |                             |  | $ | 0.683096 | 
|Second Quarter |  |                   | 4,599,294  |  |                     |   | 4,483,404  |                             |  |   | 0.747234 | 
|Third Quarter  |  |                   | 4,142,789  |  |                     |   | 4,063,290  |                             |  |   | 0.677215 | 
|Fourth Quarter |  |                   | 4,130,924  |  |                     |   | 4,080,054  |                             |  |   | 0.680009 | 
|               |  |                   |            |  |                     |   |            |                             |  |   |          | 
|               |  | $                 | 17,142,087 |  |                     | $ | 16,725,324 |                             |  | $ | 2.787554 | 
|               |  |                   |            |  |                     |   |            |                             |  |   |          | 
|               |  |                   |           
|2009           |  |                   |            |  |                     |   |            |                             |  |   |          | 
|               |  |                   |           
|First Quarter  |  | $                 | 2,805,299  |  |                     | $ | 2,669,790  |                             |  | $ | 0.444965 | 
|Second Quarter |  |                   | 2,389,205  |  |                     |   | 2,288,694  |                             |  |   | 0.381449 | 
|Third Quarter  |  |                   | 2,894,511  |  |                     |   | 2,765,082  |                             |  |   | 0.460847 | 
|Fourth Quarter |  |                   | 3,653,530  |  |                     |   | 3,592,572  |                             |  |   | 0.598762 | 
|               |  |                   |            |  |                     |   |            |                             |  |   |          | 
|               |  | $                 | 11,742,545 |  |                     | $ | 11,316,138 |                             |  | $ | 1.886023 | 
|               |  |                   |            |  |                     |   |            |                             |  |   |          | 



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Report of Independent Registered Public Accounting Firm



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



We
have audited the accompanying statements of assets, liabilities, and trust corpus of the Cross Timbers Royalty Trust as of December 31, 2010 and 2009, and the related statements of distributable income and changes in trust corpus for each of
the years in the three-year period ended December 31, 2010. We also have audited Cross Timbers Royalty Trusts internal control over financial reporting as of December 31, 2010, based on criteria established in Internal
Control  Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The trustee of Cross Timbers 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 included in the accompanying Trustees Report on 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 Cross Timbers Royalty Trust as of December 31, 2010 and 2009, and its distributable income and changes in trust corpus for each of the years in the
three-year period ended December 31, 2010, in conformity with the modified cash basis of accounting described in note 2. Also in our opinion, Cross Timbers Royalty Trust maintained, in all material respects, effective internal control over
financial reporting as of December 31, 2010, based on criteria established in Internal ControlIntegrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission.



KPMG LLP

Fort Worth, Texas

February 24, 2011



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|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, 2010.



|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, 2010. The effectiveness of the trusts internal control over financial reporting as of December 31, 2010 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, 2010 that
have materially affected, or are reasonably likely to materially affect, the trusts internal control over financial reporting.



|Item 9B. | Other Information
|-------- | -----------------



None.



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 directors, officers, and 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. 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, 2010.





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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,
17thFloor, 901 Main Street, Dallas, Texas 75202.



|Item 11. | Executive Compensation
|-------- | ----------------------



The trustee received the following annual compensation from 2008 through 2010 as specified in the trust indenture:



|                                   |  |      |      |  |                              |   |        | 
|---------------------------------- |  | ---- | ---- |  | ---------------------------- | - | ------ | 
|Name and Principal Position        |  | Year |      |  | Other AnnualCompensation (1) |  
|U.S. Trust, Bank of America        |  |      | 2010 |  |                              | $ | 8,571  | 
|Private Wealth Management, Trustee |  |      | 2009 |  |                              |   | 5,871  | 
|                                   |  |      | 2008 |  |                              |   | 15,656 | 

---

|(1) | Under the trust indenture, the trustee is entitled to an administrative fee of: (i) 1/20 of 1% of the first $100 million of the annual gross revenue of the trust,
and 1/30 of 1% of the annual gross revenue of the trust in excess of $100 million, and (ii) trustees standard hourly rates for time in excess of 300 hours annually.
|--- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



|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 January 19, 2011 Bank of America, N.A. owned, in various fiduciary capacities, 47,185 units with a
shared right to vote 25,161 of these units and no right to vote 22,024 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
75% net profits interests, XTO Energy deducts an overhead charge as reimbursement for costs associated with monitoring these interests. This charge at December 31, 2010 was $34,481 per month, or $413,772 annually (net to the trust of $310,329
annually). Included in this monthly overhead charge is a charge XTO Energy deducts as operator of the Penwell Unit and ExxonMobil deducts as operator of the Hewitt Unit. As of December 31, 2010 overhead attributable to the Penwell Unit was
$2,713 per month, or $32,556 annually (net to the trust of $24,417 annually) and overhead attributable to the Hewitt Unit was $4,538 per month, or $54,456 annually (net to the trust of $40,842 annually). These overhead charges are subject to annual
adjustment based on an oil and gas industry index.



See Item 11, Executive Compensation, for the remuneration received by the trustee from 2008 through 2010 and Item 12(b),
Security Ownership of Management, for information concerning units owned by the trustee, in various fiduciary capacities.



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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, 2010 and 2009 are:



|                   |  |      |        |  |      |   |        | 
|------------------ |  | ---- | ------ |  | ---- | - | ------ | 
|                   |  | 2010 |        |  | 2009 |  
|Audit fees         |  | $    | 79,900 |  |      | $ | 77,500 | 
|Audit-related fees |  |      |       |  |      |   |       | 
|Tax fees           |  |      |       |  |      |   |       | 
|All other fees     |  |      |       |  |      |   |       | 
|                   |  |      |        |  |      |   |        | 
|                   |  | $    | 79,000 |  |      | $ | 77,500 | 
|                   |  |      |        |  |      |   |        | 



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.



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, 2010 and 2009

Statements of Distributable Income for the years ended December 31, 2010, 2009 and 2008

Statements of Changes in Trust Corpus for the years ended December 31, 2010, 2009 and 2008

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)

Cross Timbers Royalty Trust Indenture amended and restated on January 13, 1992 by NationsBank, N.A. (now Bank of America,
N.A.), as trustee, heretofore filed as Exhibit 3.1 to the trusts Registration Statement No. 33-44385 filed with the Securities and Exchange Commission on February 19, 1992, is incorporated herein by reference.(b)

Net Overriding Royalty Conveyance (Cross Timbers Royalty Trust, 90%Texas) from South Timbers Limited Partnership, West Timbers Limited Partnership, North Timbers Limited
Partnership, East Timbers Limited Partnership, Hickory Timbers Limited Partnership, and Cross Timbers Partners, L.P. (predecessors of XTO Energy) to NCNB Texas National Bank (now Bank of America, N.A.), as trustee, dated February 12, 1991
(without Schedules A and B), heretofore filed as Exhibit 10.1 to the trusts Registration Statement No. 33-44385 filed with the Securities and Exchange Commission on February 19, 1992, is incorporated herein by
reference.




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(c)

Correction to Net Overriding Royalty Conveyance (Cross Timbers Royalty Trust, 90%Texas) from South Timbers Limited Partnership, West Timbers Limited Partnership, North
Timbers Limited Partnership, East Timbers Limited Partnership, Hickory Timbers Limited Partnership, and Cross Timbers Partners, L.P. (predecessors of XTO Energy) to NCNB Texas National Bank (now Bank of America, N.A.), as trustee, dated
September 23, 1991 (without Schedules A and B), heretofore filed as Exhibit 10.2 to the trusts Registration Statement No. 33-44385 filed with the Securities and Exchange Commission on February 19, 1992, is incorporated herein by
reference.(d)

Net Overriding Royalty Conveyance (Cross Timbers Royalty Trust, 75%Texas) from South Timbers Limited Partnership, West Timbers Limited Partnership, North Timbers Limited
Partnership, East Timbers Limited Partnership, Hickory Timbers Limited Partnership, and Cross Timbers Partners, L.P. (predecessors of XTO Energy) to NCNB Texas National Bank (now Bank of America, N.A.), as trustee, dated February 12, 1991
(without Schedules A and B), heretofore filed as Exhibit 10.5 to the trusts Registration Statement No. 33-44385 filed with the Securities and Exchange Commission on February 19, 1992, is incorporated herein by
reference.(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.



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SIGNATURES



Pursuant to the requirements of Section 13 or 15(d) of
the Securities Exchange Act of 1934, the Registrant has duly caused this Report to be signed on its behalf by the undersigned thereunto duly authorized.



|                        |  |  |  |                                                               |  |                                               
|----------------------- |  |  |  | ------------------------------------------------------------- |  | ----------------------------------------------
|                        |  |  |  | CROSS TIMBERS ROYALTY TRUST
By BANK OF AMERICA, N.A., TRUSTEE
|                        |  |  | 
|                        |  |  |  | BY                                                            |  | /S/     NANCY G.
WILLIS                       
|                        |  |  |  |                                                               |  | Nancy G. Willis Vice President                
|                        |  | 
|                        |  |  |  | EXXON MOBIL CORPORATION                                      
|                        |  |  | 
|Date: February 24, 2011 |  |  |  | BY                                                            |  | /S/     PATRICK T.
MULVA                      
|                        |  |  |  |                                                               |  | Patrick T. Mulva Vice President and Controller



(The trust has no directors or executive officers.)



39