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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, 2015 |  | 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.)
|                                                               | 
|Southwest Bank
Trustee P.O. Box 962020
Fort Worth, Texas       |  | 76162-2020                          
|(Address of Principal Executive Offices)                       |  | (Zip Code)                          

Registrants Telephone Number Including Area Code: (855) 588-7839

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   ̈        No  x

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

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

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 ̈                        |  | Smaller reporting company   ̈
|                           |  |                      |  | (Do not check if a 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, 2015 (the last business day of its most recently completed second fiscal quarter), held by non-affiliates of the registrant on that date was approximately $99 million.

At February 15, 2016, 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 TIMBERS ROYALTY TRUST

2015 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                                                                             |  |      | 17 | 
|Item 4.  |  | Mine Safety Disclosures                                                                       |  |      | 17 | 
|        
|PART II  | 
|Item 5.  |  | Market for Units of the Trust, Related Unitholder Matters and Trust Purchases of Units        |  |      | 18 | 
|Item 6.  |  | Selected Financial Data                                                                       |  |      | 18 | 
|Item 7.  |  | Trustees Discussion and Analysis of Financial Condition and Results of Operations            |  |      | 19 | 
|Item 7A. |  | Quantitative and Qualitative Disclosures about Market Risk                                    |  |      | 25 | 
|Item 8.  |  | Financial Statements and Supplementary Data                                                   |  |      | 26 | 
|Item 9.  |  | Changes in and Disagreements with Accountants on Accounting and Financial Disclosure          |  |      | 37 | 
|Item 9A. |  | Controls and Procedures                                                                       |  |      | 37 | 
|Item 9B. |  | Other Information                                                                             |  |      | 37 | 
|        
|PART III | 
|Item 10. |  | Directors, Executive Officers and Corporate Governance                                        |  |      | 38 | 
|Item 11. |  | Executive Compensation                                                                        |  |      | 38 | 
|Item 12. |  | Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters |  |      | 38 | 
|Item 13. |  | Certain Relationships and Related Transactions, and Director Independence                     |  |      | 38 | 
|Item 14. |  | Principal Accountant Fees and Services                                                        |  |      | 39 | 
|        
|PART IV  | 
|Item 15. |  | Exhibits and Financial Statement Schedules                                                    |  |      | 40 | 



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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.
Southwest Bank is now the trustee of the Trust. The principal office of the Trust is located at 2911 Turtle Creek Blvd, Suite 850, Dallas, Texas 75219 (telephone number 855-588-7839).

On January 9, 2014, U.S. Trust, Bank of America Private Wealth Management, a division of Bank of America, N.A., gave notice to unitholders that it
would resign as trustee. At the special meeting of the Trusts unitholders held on June 20, 2014, the unitholders of the Trust voted to approve the proposal to appoint Southwest Bank as successor trustee of the Trust effective
August 29, 2014.

The Trusts internet web site is www.crt-crosstimbers.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.

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, 2015 was $38,430 ($28,823 net to the Trust). XTO Energy deducts an overhead charge as operator of the Hewitt Unit. As of December 31, 2015,
monthly overhead attributable to the Hewitt Unit was $5,490 ($4,118 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.



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Costs exceeded revenues on properties underlying the Texas working interest in January 2015 through July
2015, September 2015 through December 2015, January 2014, November 2014, January 2013, March 2013 and April 2013, and on properties underlying the Oklahoma working interest in March 2015 through July 2015, September
2015 through December 2015 and June 2014. Remaining cumulative excess costs totaled $2,026,071 ($1,519,553 net to the Trust) for the period ended December 31, 2015. 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 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.

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 56% of the net profits
income received by the Trust during 2015, as well as 66% of the estimated proved reserves of the net profits interests at December 31, 2015 (based on estimated future net cash flows using 12-



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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.

The oil and gas industry has been challenged throughout 2015 with abundance of crude oil and natural gas supplies causing commodity prices to decrease.
However, current market conditions are not necessarily indicative of future conditions.



|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 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 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. A significant decline in oil or natural gas prices
could have a material adverse effect on the amount of oil and natural gas that is economic to produce, Trust net profits (and therefore cash available for distribution to unitholders) and proved reserves attributable to the Trusts interests.
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,



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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 in January 2015 through July
2015, September 2015 through December 2015, January 2014, November 2014, January 2013, March 2013 and April 2013, and on properties underlying the Oklahoma working interest in March 2015 through July 2015, September
2015 through December 2015 and June 2014), 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 and operations 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.

Future royalty income may be subject to risks relating to the creditworthiness of third parties.

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. This creditworthiness may be impacted by the price of crude oil and natural gas.

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

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



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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. Future maintenance and development projects on the underlying properties will affect the quantity of proved reserves and can offset the reduction in the depletion of 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 geopolitical hostilities could adversely affect trust distributions or the market price of the Trust units.

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

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

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

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 will also be terminated if it fails to generate
sufficient gross proceeds.

The Trust may sell the net profits interests if the holders of 80% or more of the outstanding 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



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at least $1,000,000 per year over any successive 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 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:



| |  |  | continued low oil or natural gas prices;
| | - |  | ----------------------------------------

| |  |  | 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.
| | - |  | --------------------------------------------------------------------------------------------------------



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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. See Regulation on pp. 13-17
and Greenhouse Gas Emissions and Climate Change Regulations on p. 23.



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

As of December 31, 2015, 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 holders of
at least 80% or more of the outstanding trust units or at such time as trust gross revenue is less than $1 million for two successive years.

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, 2015 is approximately 10 years. This index
is calculated using total proved reserves and estimated 2016 production for the underlying properties. The projected 2016 production is from proved developed producing reserves as of December 31, 2015. 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 34% oil and 66% natural gas. The underlying properties also include
certain nonproducing properties in Texas, Oklahoma and New Mexico that are primarily mineral interests.



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Producing Acreage, Wells and Drilling

90% Net Profits Interests Underlying Royalties.Royalty and overriding royalty properties underlying the 90% net profits
interests represent 94% of the discounted future net cash flows from trust proved reserves at December 31, 2015. Approximately 69% of the discounted future net cash flows from the 90% net profits interests are from gas reserves, totaling 16.4
Bcf. Oil reserves allocated to the 90% net profits interests are primarily located in West Texas and are estimated to be 428,000 Bbls at December 31, 2015.

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 64% of the Trusts gas sales volumes and 33% of the net
profits income for 2015. The trusts estimated proved gas reserves from this region totaled 13.5 Bcf at December 31, 2015, or approximately 82% of trust total gas reserves at that date. XTO Energy estimates that underlying royalties in the
San Juan Basin include more than 4,854 gross (approximately 46.9 net) wells, covering almost 60,000 gross acres. Approximately half of these wells are operated by BP America Production Company or ConocoPhillips.

San Juan Basin oil and gas accumulations, inclusive of the Fruitland Coal, Pictured Cliffs, Mancos, Mesaverde, and Dakota formations, have produced
within the basin for over 90 years. Although these reservoirs have seen almost a century of development, numerous upside opportunities are still available to basin operators via down-spacing drilling, recompletions, lateral drilling, and lease cost
optimizations. Recently, operators have moved development toward the more liquid-rich portions of the basin through the following:



| |  |  | reduced dry gas drilling with a shift toward horizontal drilling in the more liquids-rich areas
| | - |  | -----------------------------------------------------------------------------------------------

| |  |  | lease optimization via compression upgrades, restimulations, and improved artificial lift
| | - |  | -----------------------------------------------------------------------------------------

| |  |  | basinal work to rail crude oil out of basin to improve pricing
| | - |  | --------------------------------------------------------------

| |  |  | stable gas pipeline infrastructure
| | - |  | ----------------------------------

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 208,720 gross (approximately 38,971
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 Hewitt Unit, which is one of the properties underlying the Oklahoma 75% net profits interests. With the exception of the 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
55,000 Bbls at year-end 2015. Proved reserves from these interests represent 6% of the discounted future net cash flows of the trusts proved reserves at December 31, 2015.



9



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##### Table of Contents

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  | % |                 |  | 1.5 | %
|North Central Levelland |  | Hockley/Texas   |  | Apache Corporation               |  |                        | 3.2  | % |                 |  | 2.6 | %
|Penwell                 |  | Ector/Texas     |  | Cross Timbers Energy, LLC        |  |                        | 5.2  | % |                 |  | 4.6 | %
|Sharon Ridge Canyon     |  | Borden/Texas    |  | Occidental Permian, Ltd.         |  |                        | 4.3  | % |                 |  | 2.8 | %
|Hewitt                  |  | Carter/Oklahoma |  | XTO Energy Inc.                  |  |                        | 11.3 | % |                 |  | 9.9 | %
|Wildcat Jim Penn        |  | Carter/Oklahoma |  | Citation Oil and Gas Corporation |  |                        | 8.6  | % |                 |  | 7.5 | %
|South Graham Deese      |  | Carter/Oklahoma |  | Linn Energy, LLC                 |  |                        | 9.2  | % |                 |  | 8.7 | %

The underlying working interest properties consist of 3,814 gross (2,995 net) producing acres. As of December 31,
2015, there were 1,468 gross (73.0 net) productive oil wells and no wells in process of drilling on these properties. There were 12 gross (1.0 net) wells drilled in 2015, 5 gross (0.3 net) wells drilled in 2014 and 11 gross (1.0 net) wells drilled
in 2013.

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.

Total 2015 development costs were $2,697,664, down
20% from 2014 development costs of $3,373,537. Development costs were lower in 2015 because of decreased development activity and costs related to non-operated Texas and Oklahoma oil properties underlying the 75% net profits interest. January and
February 2016 development costs totaled approximately $294,000, primarily incurred in fourth quarter 2015.

As reported to XTO Energy by unit
operators in February of each year, budgeted development costs were $4.4 million for 2015 and $2.4 million for 2014. 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 $1.0 million for 2016 and $1.1 million for 2017. Changes in oil or natural gas prices could impact future development plans on the underlying properties.

Costs exceeded revenues on properties underlying the Texas working interest in January 2015 through July 2015, September 2015 through December
2015, January 2014, November 2014, January 2013, March 2013 and April 2013, and on properties underlying the Oklahoma working interest in March 2015 through July 2015, September 2015 through December 2015 and June 2014.
Remaining cumulative excess costs totaled $2,026,071 ($1,519,553 net to the trust) for the period ended December 31, 2015. 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.



10



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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, 2015:



|                          |  |                       |     |  |                       |              |        |                                                 |            |  |          |  |  |  |        |  |  |   |        |  |  |   |        | 
|------------------------- |  | --------------------- | --- |  | --------------------- | ------------ | ------ | ----------------------------------------------- | ---------- |  | -------- |  |  |  | ------ |  |  | - | ------ |  |  | - | ------ | 
|                          |  | 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            |  |                       | 22  |  |                       |              | 15,014 |                                                 |            |  | 20       |  |  |  | 13,512 |  |  | $ | 32,723 |  |  | $ | 16,922 | 
|Other New Mexico          |  |                       | 29  |  |                       |              | 72     |                                                 |            |  | 26       |  |  |  | 91     |  |  |   | 1,388  |  |  |   | 703    | 
|Texas                     |  |                       | 379 |  |                       |              | 1,976  |                                                 |            |  | 341      |  |  |  | 1,779  |  |  |   | 21,317 |  |  |   | 11,708 | 
|Oklahoma                  |  |                       | 46  |  |                       |              | 1,269  |                                                 |            |  | 41       |  |  |  | 1,064  |  |  |   | 4,145  |  |  |   | 2,451  | 
|                          |  |                       |     |  |                       |              |        |                                                 |            |  |          |  |  |  |        |  |  |   |        |  |  |   |        | 
|Total                     |  |                       | 476 |  |                       |              | 18,331 |                                                 |            |  | 428      |  |  |  | 16,446 |  |  |   | 59,573 |  |  |   | 31,784 | 
|                          |  |                       |     |  |                       |              |        |                                                 |            |  |          |  |  |  |        |  |  |   |        |  |  |   |        | 
|75% Net Profits Interests |  |                       |     |  |                       |              |        |                                                 |            |  |          |  |  |  |        |  |  |   |        |  |  |   |        | 
|Texas                     |  |                       | 102 |  |                       |              | 192    |                                                 |            |  | 16       |  |  |  | 30     |  |  |   | 1,091  |  |  |   | 805    | 
|Oklahoma                  |  |                       | 260 |  |                       |              | 19     |                                                 |            |  | 39       |  |  |  | 3      |  |  |   | 1,594  |  |  |   | 1,153  | 
|                          |  |                       |     |  |                       |              |        |                                                 |            |  |          |  |  |  |        |  |  |   |        |  |  |   |        | 
|Total                     |  |                       | 362 |  |                       |              | 211    |                                                 |            |  | 55       |  |  |  | 33     |  |  |   | 2,685  |  |  |   | 1,958  | 
|                          |  |                       |     |  |                       |              |        |                                                 |            |  |          |  |  |  |        |  |  |   |        |  |  |   |        | 
|TOTAL                     |  |                       | 838 |  |                       |              | 18,542 |                                                 |            |  | 483      |  |  |  | 16,479 |  |  | $ | 62,258 |  |  | $ | 33,742 | 
|                          |  |                       |     |  |                       |              |        |                                                 |            |  |          |  |  |  |        |  |  |   |        |  |  |   |        | 



|(a) | Based on 12-month average oil price of $46.58 per Bbl and $2.83 per Mcf for gas, based on the first-day-of-the-month price for each month in the period. Discounted estimated future net cash flows from proved reserves
decreased 65% from year-end 2014 to 2015, primarily because of a 51% decrease in natural gas prices, a 47% decrease in oil prices, reserve revisions due to lower prices and 2015 production.
|--- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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

When crude oil and natural gas prices are in the range seen in late 2015 and early 2016 for an extended period of time, under the SEC definition of
proved reserves, certain quantities of oil and natural gas may no longer qualify as proved reserves.

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   |  |                       | 838 |  |                       |  | 18,542 |           |  |  | 483      |  |  |  | 16,479 | 
|Proved undeveloped reserves |  |                       |    |  |                       |  |       |           |  |  |         |  |  |  |       | 
|                            |  |                       |     |  |                       |  |        |           |  |  |          |  |  |  |        | 
|Total proved reserves       |  |                       | 838 |  |                       |  | 18,542 |           |  |  | 483      |  |  |  | 16,479 | 
|                            |  |                       |     |  |                       |  |        |           |  |  |          |  |  |  |        | 

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



11



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##### Table of Contents

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, 2015, 2014, 2013 and 2012. Miller and Lents primary technical person responsible for calculating the
trusts reserves has more than 40 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.

When crude oil and natural gas prices are in the range seen in late 2015 and early 2016 for an extended period of time, under
the SEC definition of proved reserves, certain quantities of oil and natural gas may no longer qualify as proved reserves. Amounts required to be de-booked as proved reserves on an SEC basis are subject to being re-booked as proved reserves at some
point in the future when price levels recover.

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 were
as follows:



|                       |  |                           |           |  |                           |  |           |       |  |  |           |  |  |      |         |  |      |  |         |      |  |  |         |  |  |      |           |  |  |  |           |  |  |  |           | 
|---------------------- |  | ------------------------- | --------- |  | ------------------------- |  | --------- | ----- |  |  | --------- |  |  | ---- | ------- |  | ---- |  | ------- | ---- |  |  | ------- |  |  | ---- | --------- |  |  |  | --------- |  |  |  | --------- | 
|                       |  | 90% Net Profits Interests |           |  | 75% Net Profits Interests |  |           | Total | 
|                       |  | 2015                      |           |  | 2014                      |  |           | 2013  |  |  | 2015      |  |  | 2014 |         |  | 2013 |  |         | 2015 |  |  | 2014    |  |  | 2013 |          
|Production             |  |                           |           |  |                           |  |           |       |  |  |           |  |  |      |         |  |      |  |         |      |  |  |         |  |  |      |           |  |  |  |           |  |  |  |           | 
|Underlying Properties  |  |                           |           |  |                           |  |           |       |  |  |           |  |  |      |         |  |      |  |         |      |  |  |         |  |  |      |           |  |  |  |           |  |  |  |           | 
|OilSales (Bbls)       |  |                           | 77,221    |  |                           |  | 72,101    |       |  |  | 67,989    |  |  |      | 154,836 |  |      |  | 149,286 |      |  |  | 140,358 |  |  |      | 232,057   |  |  |  | 221,387   |  |  |  | 208,347   | 
|Average per day (Bbls) |  |                           | 212       |  |                           |  | 198       |       |  |  | 186       |  |  |      | 424     |  |      |  | 409     |      |  |  | 385     |  |  |      | 636       |  |  |  | 607       |  |  |  | 571       | 
|GasSales (Mcf)        |  |                           | 1,593,141 |  |                           |  | 1,605,306 |       |  |  | 1,586,334 |  |  |      | 22,897  |  |      |  | 24,062  |      |  |  | 54,881  |  |  |      | 1,616,038 |  |  |  | 1,629,368 |  |  |  | 1,641,215 | 
|Average per day (Mcf)  |  |                           | 4,365     |  |                           |  | 4,398     |       |  |  | 4,346     |  |  |      | 63      |  |      |  | 66      |      |  |  | 150     |  |  |      | 4,428     |  |  |  | 4,464     |  |  |  | 4,496     | 
|Net Profits Interests  |  |                           |           |  |                           |  |           |       |  |  |           |  |  |      |         |  |      |  |         |      |  |  |         |  |  |      |           |  |  |  |           |  |  |  |           | 
|OilSales (Bbls)       |  |                           | 64,853    |  |                           |  | 62,919    |       |  |  | 59,208    |  |  |      | 3,214   |  |      |  | 32,677  |      |  |  | 26,573  |  |  |      | 68,067    |  |  |  | 95,596    |  |  |  | 85,781    | 
|Average per day (Bbls) |  |                           | 178       |  |                           |  | 172       |       |  |  | 162       |  |  |      | 9       |  |      |  | 90      |      |  |  | 73      |  |  |      | 187       |  |  |  | 262       |  |  |  | 235       | 
|GasSales (Mcf)        |  |                           | 1,409,136 |  |                           |  | 1,458,575 |       |  |  | 1,416,801 |  |  |      | 175     |  |      |  | 5,732   |      |  |  | 10,321  |  |  |      | 1,409,311 |  |  |  | 1,464,307 |  |  |  | 1,427,122 | 
|Average per day (Mcf)  |  |                           | 3,861     |  |                           |  | 3,996     |       |  |  | 3,882     |  |  |      |        |  |      |  | 16      |      |  |  | 28      |  |  |      | 3,861     |  |  |  | 4,012     |  |  |  | 3,910     | 
|                       |  |                           |           |  |                           |  |           |       | 
|Average Sales Price    |  |                           |           |  |                           |  |           |       |  |  |           |  |  |      |         |  |      |  |         |      |  |  |         |  |  |      |           |  |  |  |           |  |  |  |           | 
|Oil (per Bbl)          |  |                           | $58.44    |  |                           |  | $91.15    |       |  |  | $90.41    |  |  |      | $49.72  |  |      |  | $91.64  |      |  |  | $89.49  |  |  |      | $52.62    |  |  |  | $91.48    |  |  |  | $89.79    | 
|Gas (per Mcf)          |  |                           | $4.49     |  |                           |  | $6.94     |       |  |  | $6.34     |  |  |      | $7.77   |  |      |  | $11.21  |      |  |  | $5.73   |  |  |      | $4.54     |  |  |  | $7.00     |  |  |  | $6.32     | 



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



|                            |  |                                  |           |  |      |  |           |      |  |  |           | 
|--------------------------- |  | -------------------------------- | --------- |  | ---- |  | --------- | ---- |  |  | --------- | 
|                            |  | Underlying Gas Production (Mcf)  |          
|Conveyance                  |  | 2015                             |           |  | 2014 |  |           | 2013 | 
|New Mexico royalty interest |  |                                  | 1,008,064 |  |      |  | 1,111,622 |      |  |  | 1,130,420 | 
|Oklahoma royalty interest   |  |                                  | 349,439   |  |      |  | 276,549   |      |  |  | 216,679   | 
|Texas royalty interest      |  |                                  | 235,638   |  |      |  | 217,135   |      |  |  | 239,235   | 
|Texas working interest      |  |                                  | 14,939    |  |      |  | 11,490    |      |  |  | 16,792    | 
|Oklahoma working interest   |  |                                  | 7,958     |  |      |  | 12,572    |      |  |  | 38,089    | 
|                            |  |                                  |           |  |      |  |           |      |  |  |           | 
|Total                       |  |                                  | 1,616,038 |  |      |  | 1,629,368 |      |  |  | 1,641,215 | 
|                            |  |                                  |           |  |      |  |           |      |  |  |           | 
|                            | 
|                            |  | Underlying Oil Production (Bbls) |          
|Conveyance                  |  | 2015                             |           |  | 2014 |  |           | 2013 | 
|New Mexico royalty interest |  |                                  | 5,672     |  |      |  | 6,382     |      |  |  | 4,496     | 
|Oklahoma royalty interest   |  |                                  | 22,075    |  |      |  | 14,914    |      |  |  | 9,518     | 
|Texas royalty interest      |  |                                  | 49,474    |  |      |  | 50,804    |      |  |  | 53,975    | 
|Texas working interest      |  |                                  | 60,133    |  |      |  | 57,928    |      |  |  | 54,261    | 
|Oklahoma working interest   |  |                                  | 94,703    |  |      |  | 91,359    |      |  |  | 86,097    | 
|                            |  |                                  |           |  |      |  |           |      |  |  |           | 
|Total                       |  |                                  | 232,057   |  |      |  | 221,387   |      |  |  | 208,347   | 
|                            |  |                                  |           |  |      |  |           |      |  |  |           | 

Nonproducing Acreage

The
underlying nonproducing royalties contain approximately 300,000 gross (approximately 25,000 net) acres in Texas, Oklahoma and New Mexico which were nonproducing at the date of the trusts creation. The Trust 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.



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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.

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.

Federal Income Taxes

For federal income tax
purposes, the Trust constitutes a fixed investment trust that is taxed as a grantor trust. A grantor trust is not subject to tax at the Trust level. The unitholders 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 have been received or accrued by each unitholder at the time such income is received or accrued by the Trust and not when distributed by the trust.

Because the Trust is a grantor trust for federal tax purposes, each unitholder is taxed directly on his proportionate share of income, deductions and
credits of the Trust consistent with each such unitholders taxable year and method of accounting and without regard to the taxable year or method of accounting employed by the trust. The income of the Trust consists primarily of a specified
share of the net profits from the sale of oil and natural gas produced from the underlying properties. During 2015, the Trust incurred administration expenses and earned interest income on funds held for distribution.

The net profits interests constitute economic interests in oil and gas properties for federal tax purposes. Each unitholder is entitled to
amortize the cost of the units through cost depletion over the life of the net profits interests or, if



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greater, through percentage depletion equal to 15 percent of gross income. Unlike cost depletion, percentage depletion is not limited to a unitholders depletable tax basis in the units.
Rather, a unitholder is entitled to a percentage depletion deduction as long as the applicable underlying properties generate gross income. Unitholders may compute both percentage depletion and cost depletion from each property and claim the larger
amount as a deduction on their income tax returns.

If a taxpayer disposes of any Section 1254 property (certain oil, gas, geothermal or
other mineral property), and the adjusted basis of such property includes adjustments for depletion deductions under Section 611 of the Internal Revenue Code (the Code), the taxpayer generally must recapture the amount deducted for
depletion as ordinary income (to the extent of gain realized on the disposition of the property). This depletion recapture rule applies to any disposition of property that was placed in service by the taxpayer after December 31, 1986. Detailed
rules set forth in Sections 1.1254-1 through 1.1254-6 of the U.S. Treasury Regulations govern dispositions of property after March 13, 1995. The Internal Revenue Service likely will take the position that a unitholder must recapture depletion
upon the disposition of a unit.

Interest and net profits income attributable to ownership of units and any gain on the sale thereof are considered
portfolio income, and not income from a passive activity, to the extent a unitholder acquires and holds units as an investment and not in the ordinary course of a trade or business. Therefore, interest and net profits income attributable
to ownership of units generally may not be offset by losses from any passive activities.

Individuals may incur expenses in connection with the
acquisition or maintenance of trust units. These expenses may be deductible as miscellaneous itemized deductions only to the extent that such expenses exceed 2 percent of the individuals adjusted gross income.

Under current law, the highest marginal U.S. federal income tax rate applicable to ordinary income of individuals is 39.6%, and the highest marginal
U.S. federal income tax rate applicable to long-term capital gains (generally, gains from the sale or exchange of certain investment assets held for more than one year) and qualified dividends of individuals is 20%. Such marginal tax rates may be
effectively increased by up to 1.2% due to the phaseout of personal exemptions and the limitations on itemized deductions. The highest marginal U.S. federal income tax rate applicable to corporations is 35%, and such rate applies to both ordinary
income and capital gains.

Section 1411 of the Code imposes a 3.8% Medicare tax on certain investment income earned by individuals, estates,
and trusts for taxable years beginning after December 31, 2012. For these purposes, investment income generally will include a unitholders allocable share of the trusts interest and royalty income plus the gain recognized from a
sale of trust units. In the case of an individual, the tax is imposed on the lesser of (i) the individuals net investment income from all investments, or (ii) the amount by which the individuals modified adjusted gross income
exceeds specified threshold levels depending on such individuals federal income tax filing status. In the case of an estate or trust, the tax is imposed on the lesser of (i) undistributed net investment income, or (ii) the excess
adjusted gross income over the dollar amount at which the highest income tax bracket applicable to an estate or trust begins.

The difference
between the per-unit taxable income for any period and the per-unit cash distributions, if any, reported for such period is attributable to (i) items that are not currently deductible, such as an increase in the cash reserve maintained by the
Trust for the payment of future expenditures, (ii) the current deduction of expenses that are paid with amounts previously reserved and (iii) items that do not constitute taxable income, such as a decrease in the cash reserve maintained by
the Trust and/or a return of capital. In 2015, the trustee elected to reserve amounts from monthly distributions to establish an administrative expense reserve, so the taxable income per period has frequently differed from the actual amount
distributed to unitholders.

Pursuant to the Foreign Account Tax Compliance Act (commonly referred to as FATCA), distributions from the
Trust to foreign financial institutions and certain other non-financial foreign entities may be subject to U.S. withholding taxes. Specifically, certain withholdable payments (including certain royalties, interest
and other gains or income from U.S. sources) made to a foreign financial institution or non-financial foreign entity will generally be subject to the withholding tax unless the foreign financial institution or non-financial foreign entity complies
with certain information reporting, withholding,



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identification, certification and related requirements imposed by FATCA. Foreign financial institutions located in jurisdictions that have an intergovernmental agreement with the United States
governing FATCA may be subject to different rules.

The Treasury Department issued guidance providing that the FATCA withholding rules described
above generally will apply to qualifying payments made after June 30, 2014. Foreign unitholders are encouraged to consult their own tax advisors regarding the possible implications of these withholding provisions on their investment in trust
units.

Some trust units are held by middlemen, as such term is broadly defined in U.S. Treasury Regulations (and includes custodians, nominees,
certain joint owners, and brokers holding an interest for a customer in street name, collectively referred to herein as middlemen). Therefore, the trustee considers the Trust to be a non-mortgage widely held fixed investment trust
(WHFIT) for U.S. federal income tax purposes. Southwest Bank, EIN: 75-1105980, Post Office Box 962020, Fort Worth, Texas, 76162-2020, telephone number 1-855-588-7839, email address trustee@crt-crosstimbers.com, is the representative of
the Trust that will provide tax information in accordance with applicable U.S. Treasury Regulations governing the information reporting requirements of the Trust as a WHFIT. Tax information is also posted by the trustee at
www.crt-crosstimbers.com. Notwithstanding the foregoing, the middlemen holding trust units on behalf of unitholders, and not the trustee of the trust, are solely responsible for complying with the information reporting requirements under the
U.S. Treasury Regulations with respect to such trust units, including the issuance of IRS Forms 1099 and certain written tax statements. Unitholders whose trust units are held by middlemen should consult with such middlemen regarding the information
that will be reported to them by the middlemen with respect to the Trust units.

Unitholders should consult their tax advisors regarding trust tax
compliance matters.

State Taxes

All
revenues from the Trust are from sources within Texas, Oklahoma or New Mexico. Because it distributes all of its net income to unitholders, the Trust has not been taxed at the Trust level in New Mexico or Oklahoma. While the Trust has not owed tax,
the trustee is required to file a return with Oklahoma reflecting the income and deductions of the Trust attributable to properties located in that state, along with a schedule that includes information regarding distributions to unitholders. Texas
does not impose a state income tax, so no part of the trusts income will be subject to income tax at the Trust level in Texas. Oklahoma and New Mexico tax the income of nonresidents from real property located within those states, and the Trust
has been advised by counsel that those states will each tax nonresidents on income from the net profits interests located in those states. Oklahoma and New Mexico also impose a corporate income tax that may apply to unitholders organized as
corporations (subject to certain exceptions for S corporations and limited liability companies, depending on their treatment for federal tax purposes).

Texas imposes a franchise tax at a rate of .75% on gross revenues less certain deductions, as specifically set forth in the Texas franchise tax
statutes. Entities subject to tax generally include trusts and most other types of entities that provide limited liability protection, unless otherwise exempt. Trusts that receive at least 90% of their federal gross income from designated passive
sources, including royalties from mineral properties and other non-operated mineral interest income, and do not receive more than 10% of their income from operating an active trade or business, generally are exempt from the Texas franchise tax as
passive entities. The Trust has been and expects to continue to be exempt from Texas franchise tax as a passive entity. Because the Trust should be exempt from Texas franchise tax at the Trust level as a passive entity, each unitholder
that is considered a taxable entity under the Texas franchise tax will generally be required to include its Texas portion of trust revenues in its own Texas franchise tax computation. This revenue is sourced to Texas under provisions of the Texas
Administrative Code providing that such income is sourced according to the principal place of business of the trust, which is Texas.

Each
unitholder should consult his or her own tax advisor regarding state tax requirements, if any, applicable to such persons ownership of trust units.

State Tax Withholding

Several states have
enacted legislation requiring state income tax withholding from nonresident recipients of oil and gas proceeds. After consultation with its tax counsel, the trustee believes that it is not required to withhold on payments



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made to the unitholders. However, regulations are subject to change by the various states, which could change this conclusion. Should amounts be withheld on payments made to the Trust or the
unitholders, distributions to the unitholders would be reduced by the required amount, subject to the filing of a claim for refund by the Trust or unitholders for such amount.

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. | Mine Safety Disclosures
|------- | -----------------------

Not Applicable.



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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 2015 and 2014:



|        |  |             |       |  |                       |   |       |  |  |   |          | 
|------- |  | ----------- | ----- |  | --------------------- | - | ----- |  |  | - | -------- | 
|        |  | Sales Price |       |  | Distributionsper Unit |  
|Quarter |  | High        |       |  | Low                   |   |      
|2015    |  |             |       |  |                       |   |       |  |  |   |          | 
|First   |  | $           | 23.39 |  |                       | $ | 17.25 |  |  | $ | 0.427665 | 
|Second  |  |             | 22.94 |  |                       |   | 15.03 |  |  |   | 0.289438 | 
|Third   |  |             | 16.50 |  |                       |   | 12.01 |  |  |   | 0.293444 | 
|Fourth  |  |             | 19.16 |  |                       |   | 12.01 |  |  |   | 0.344231 | 
|        |  |             |       |  |                       |   |       |  |  |   |          | 
|        |  |             |       |  |                       |   |       |  |  | $ | 1.354778 | 
|        |  |             |       |  |                       |   |       |  |  |   |          | 
|        |  |             |      
|2014    |  |             |       |  |                       |   |       |  |  |   |          | 
|First   |  | $           | 32.70 |  |                       | $ | 28.90 |  |  | $ | 0.700660 | 
|Second  |  |             | 38.05 |  |                       |   | 30.67 |  |  |   | 0.627709 | 
|Third   |  |             | 34.00 |  |                       |   | 30.10 |  |  |   | 0.756270 | 
|Fourth  |  |             | 31.98 |  |                       |   | 17.04 |  |  |   | 0.572911 | 
|        |  |             |       |  |                       |   |       |  |  |   |          | 
|        |  |             |       |  |                       |   |       |  |  | $ | 2.657550 | 
|        |  |             |       |  |                       |   |       |  |  |   |          | 

At December 31, 2015, there were 6,000,000 units outstanding and approximately 231 unitholders of record; 5,847,209
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 |           
|                              |  | 2015                   |            |  | 2014 |   |            | 2013 |  |   | 2012       |  |  | 2011 |           
|Net Profits Income            |  | $                      | 8,884,319  |  |      | $ | 16,449,036 |      |  | $ | 14,290,356 |  |  | $    | 15,283,504 |  |  | $ | 18,381,657 | 
|Distributable Income          |  |                        | 8,128,668  |  |      |   | 15,945,300 |      |  |   | 13,887,594 |  |  |      | 14,889,588 |  |  |   | 17,956,494 | 
|Distributable Income per Unit |  |                        | 1.354778   |  |      |   | 2.657550   |      |  |   | 2.314599   |  |  |      | 2.481598   |  |  |   | 2.992749   | 
|Distributions per Unit        |  |                        | 1.354778   |  |      |   | 2.657550   |      |  |   | 2.314599   |  |  |      | 2.481598   |  |  |   | 2.992749   | 
|Total Assets at Year-End      |  |                        | 11,511,940 |  |      |   | 12,272,598 |      |  |   | 12,935,109 |  |  |      | 13,840,567 |  |  |   | 14,629,000 | 



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|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) |  
|                                   |  | 2015                      |            |   | 2014                        |   |            | 2013 |  |   | 2015       |  |  | 2014 |          
|Sales Volumes                      |  |                           |            |   |                             |   |            |      |  |   |            |  |  |      |           |   |  |   |           |  
|Oil (Bbls)(b)                      |  |                           |            |   |                             |   |            |      |  |   |            |  |  |      |           |   |  |   |           |  
|Underlying properties              |  |                           | 232,057    |   |                             |   | 221,387    |      |  |   | 208,347    |  |  |      | 56,619    |   |  |   | 58,165    |  
|Average per day                    |  |                           | 636        |   |                             |   | 607        |      |  |   | 571        |  |  |      | 615       |   |  |   | 632       |  
|Net profits interests              |  |                           | 68,067     |   |                             |   | 95,596     |      |  |   | 85,781     |  |  |      | 13,977    |   |  |   | 23,316    |  
|Gas (Mcf)(b)                       |  |                           |            |   |                             |   |            |      |  |   |            |  |  |      |           |   |  |   |           |  
|Underlying properties              |  |                           | 1,616,038  |   |                             |   | 1,629,368  |      |  |   | 1,641,215  |  |  |      | 509,306   |   |  |   | 365,268   |  
|Average per day                    |  |                           | 4,428      |   |                             |   | 4,464      |      |  |   | 4,496      |  |  |      | 5,536     |   |  |   | 3,970     |  
|Net profits interests              |  |                           | 1,409,311  |   |                             |   | 1,464,307  |      |  |   | 1,427,122  |  |  |      | 447,769   |   |  |   | 323,111   |  
|Average Sales Price                |  |                           |            |   |                             |   |            |      |  |   |            |  |  |      |           |   |  |   |           |  
|Oil (per Bbl)                      |  |                           | $52.62     |   |                             |   | $91.48     |      |  |   | $89.79     |  |  |      | $43.74    |   |  |   | $86.61    |  
|Gas (per Mcf)                      |  |                           | $4.54      |   |                             |   | $7.00      |      |  |   | $6.32      |  |  |      | $4.67     |   |  |   | $6.19     |  
|Revenues                           |  |                           |            |   |                             |   |            |      |  |   |            |  |  |      |           |   |  |   |           |  
|Oil sales                          |  | $                         | 12,211,006 |   |                             | $ | 20,251,792 |      |  | $ | 18,707,290 |  |  | $    | 2,476,400 |   |  | $ | 5,037,786 |  
|Gas sales                          |  |                           | 7,337,579  |   |                             |   | 11,413,196 |      |  |   | 10,379,310 |  |  |      | 2,379,549 |   |  |   | 2,260,838 |  
|                                   |  |                           |            |   |                             |   |            |      |  |   |            |  |  |      |           |   |  |   |           |  
|Total Revenues                     |  |                           | 19,548,585 |   |                             |   | 31,664,988 |      |  |   | 29,086,600 |  |  |      | 4,855,949 |   |  |   | 7,298,624 |  
|                                   |  |                           |            |   |                             |   |            |      |  |   |            |  |  |      |           |   |  |   |           |  
|Costs                              |  |                           |            |   |                             |   |            |      |  |   |            |  |  |      |           |   |  |   |           |  
|Taxes, transportation and other(e) |  |                           | 2,714,689  |   |                             |   | 3,882,386  |      |  |   | 3,620,061  |  |  |      | 739,151   |   |  |   | 845,790   |  
|Production expense(c)              |  |                           | 6,189,352  |   |                             |   | 5,753,938  |      |  |   | 5,583,624  |  |  |      | 1,482,217 |   |  |   | 1,569,801 |  
|Development costs                  |  |                           | 2,697,664  |   |                             |   | 3,373,537  |      |  |   | 3,481,306  |  |  |      | 365,653   |   |  |   | 890,967   |  
|Excess costs(d)                    |  |                           | (1,972,100 | ) |                             |   | (53,971    | )    |  |   | 1,405      |  |  |      | (302,364  | ) |  |   | (54,087   | )
|                                   |  |                           |            |   |                             |   |            |      |  |   |            |  |  |      |           |   |  |   |           |  
|Total Costs                        |  |                           | 9,629,605  |   |                             |   | 12,955,890 |      |  |   | 12,686,396 |  |  |      | 2,284,657 |   |  |   | 3,252,471 |  
|                                   |  |                           |            |   |                             |   |            |      |  |   |            |  |  |      |           |   |  |   |           |  
|Other Proceeds                     |  |                           |            |   |                             |   |            |      |  |   |            |  |  |      |           |   |  |   |           |  
|Interest income(e)                 |  |                           |           |   |                             |   | 210,242    |      |  |   |           |  |  |      |          |   |  |   |          |  
|Net Proceeds                       |  | $                         | 9,918,980  |   |                             | $ | 18,919,340 |      |  | $ | 16,400,204 |  |  | $    | 2,571,292 |   |  | $ | 4,046,153 |  
|                                   |  |                           |            |   |                             |   |            |      |  |   |            |  |  |      |           |   |  |   |           |  
|Net Profits Income                 |  | $                         | 8,884,319  |   |                             | $ | 16,449,036 |      |  | $ | 14,290,356 |  |  | $    | 2,314,162 |   |  | $ | 3,530,797 |  
|                                   |  |                           |            |   |                             |   |            |      |  |   |            |  |  |      |           |   |  |   |           |  



|(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. As product prices change, the
trusts share of the production volumes is impacted as the quantity of production to cover expenses in reaching the net profits break-even level changes inversely with price. As such, the underlying property production volume changes may not
correlate with the trusts net profit share of those volumes in any given period. Therefore, comparative discussion of oil and gas sales volumes is based on the underlying properties.
|--- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



|(c) | Production expense is primarily from seven working interest properties in the 75% net profits interest. Six 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, 2015, this charge was $38,430 per month (including a monthly overhead charge of $5,490 which XTO Energy deducts as operator of the Hewitt Unit) and is subject to
adjustment each May based on an oil and gas industry index.
|--- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



|(d) | See Note 7 to Financial Statements under Item 8, Financial Statements and Supplementary Data.
|--- | ---------------------------------------------------------------------------------------------



|(e) | See Note 10 to Financial Statements under Item 8, Financial Statements and Supplementary Data.
|--- | ----------------------------------------------------------------------------------------------



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##### Table of Contents

Results of Operations

Years
Ended December 31, 2015, 2014 and 2013

Net profits income for 2015 was $8,884,319 as compared with $16,449,036 for 2014 and $14,290,356 for
2013. The 46% decrease in net profits income from 2014 to 2015 was primarily because of lower oil and gas prices ($10.4 million) and a one-time purchaser refund included in 2014 ($0.5 million), partially offset by excess costs on the Texas and
Oklahoma working interest properties in 2015 ($1.4 million), decreased taxes, transportation and other costs ($1.3 million) and lower development costs ($0.5 million). The 15% increase in net profits income from 2013 to 2014 was primarily because of
higher oil and gas prices ($1.3 million), increased oil production ($1.0 million) and a one-time purchaser refund included in 2014 ($0.5 million), partially offset by increased taxes, transportation and other costs ($0.5 million). During 2015, 2014
and 2013, 56%, 49% and 48%, respectively, of net profits income was derived from gas sales.

Trust administration expense was $755,694 in 2015 as
compared to $504,167 in 2014 and $403,043 in 2013. Administration expense for 2015 included $275,000 which the trustee reserved for administrative expenses. Interest income was $43 in 2015, $431 in 2014 and $281 in 2013. 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 increased 5% from 2014 to 2015 compared to a 6% increase from 2013 to 2014. Oil sales
volumes in 2015 increased from 2014 primarily because of increased production from new wells and workovers and the timing of cash receipts, partially offset by natural production decline. Oil sales volumes in 2014 increased from 2013 primarily
because of increased production from new wells and workovers and the timing of cash receipts, partially offset by natural production decline.

Gas.    Underlying gas sales volumes decreased 1% from 2014 to 2015 compared to a 1% decrease from 2013 to 2014. Gas sales
volumes in 2015 decreased from 2014 primarily because of natural production decline and the timing of cash receipts, partially offset by increased production from new wells and workovers. Gas sales volumes in 2014 decreased from 2013 primarily
because of natural production decline, partially offset by increased production from new wells and workovers and the timing of cash receipts.

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

Prices

Oil.    The average oil price for 2015 was $52.62 per Bbl, a 42% decrease from the 2014 average oil price of $91.48, which was
a 2% increase from the 2013 average price of $89.79. Oil prices are expected to remain volatile. The average NYMEX price for November 2015 through January 2016 was $37.44 per Bbl. At March 3, 2016, the average NYMEX oil price for the following
12 months was $39.29 per Bbl.

Gas.    The 2015 average gas price was $4.54 per Mcf, a 35% decrease from the 2014 average
gas price of $7.00, which was 11% higher than the 2013 average price of $6.32. Natural gas prices are affected by natural gas liquids prices,



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the level of North American production, weather, crude oil 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 2015 was $2.27 per MMBtu. At March 3, 2016, the average NYMEX gas price for the following 12 months was $2.18 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.

XTO Energy advised the trustee that lower oil prices resulted in net excess costs of $905,180 ($678,885 net to the Trust) on properties underlying the
Texas working interest for the year ended December 31, 2015. This includes net excess costs of $95,651 ($71,738 net to the Trust) for the quarter ended December 31, 2015. However, these excess costs did not reduce net proceeds from the
remaining conveyances.

XTO Energy advised the trustee that timing of cash receipts, lower oil prices and decreased oil production resulted in net
excess costs of $1,066,920 ($800,190 net to the Trust) on properties underlying the Oklahoma working interest for the year ended December 31, 2015. This includes net excess costs of $206,713 ($155,035 net to the Trust) for the quarter ended
December 31, 2015. However, these excess costs did not reduce net proceeds from the remaining conveyances.

XTO Energy has advised the trustee
that increased costs, lower oil prices and a missing purchaser payment for oil revenue resulted in net excess costs of $53,971 ($40,478 net to the Trust) on properties underlying the Texas working interest for the year ended December 31, 2014.
This included net excess costs of $54,087 ($40,565 net to the Trust) for the quarter ended December 31, 2014. However, these excess costs did not reduce net proceeds from the remaining conveyances.

XTO advised the trustee that a missing payment from a purchaser caused costs to exceed revenues by a total of $166 ($125 net to the Trust) on properties
underlying the Oklahoma working interest for the year ended December 31, 2014. However, these excess costs did not reduce net proceeds from the remaining conveyances. XTO advised the trustee that increased oil production led to the full
recovery of excess costs, plus accrued interest, of $166 ($125 net to the Trust) for the year ended December 31, 2014.

Lower oil prices and
increased costs related to the timing of cash expenditures caused costs to exceed revenues by a total of $251,863 ($188,897 net to the Trust) on properties underlying the Texas working interest for the year ended December 31, 2013. However,
these excess costs did not reduce net proceeds from the remaining conveyances. Decreased costs and increased oil prices led to the full recovery of excess costs, plus accrued interest, of $253,268 ($189,951 net to the Trust) for the year ended
December 31, 2013.

Cumulative excess costs remaining for the Texas and Oklahoma working interest conveyances as of December 31, 2015
totaled $2,026,071 ($1,519,553 net to the Trust).

Total costs deducted in the calculation of net profits income were $9.6 million in 2015, $13.0
million in 2014 and $12.7 million in 2013. The 26% decrease in costs from 2014 to 2015 is attributable to excess costs on the Texas and Oklahoma working interest properties in 2015, decreased oil and gas production taxes and other deductions related
to lower oil and gas revenues and lower development costs related to decreased development activities and costs on non-operated Texas and Oklahoma oil properties underlying the 75% net profits interest, partially offset by a one-time purchaser



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refund for coal seam gas deductions included in 2014 and increased production expense related to increased outside operated costs. The 2% increase in costs from 2013 to 2014 is attributable to
increased oil and gas production taxes and other deductions related to higher oil and gas revenues, partially offset by a one-time purchaser refund for coal seam gas deductions and increased production expense related to increased repairs and
maintenance costs, partially offset by decreased outside operated costs. In addition, the increase in 2014 total costs was partially offset by lower development costs related to decreased development activity and costs and the timing of expenditures
on non-operated Texas and Oklahoma oil properties underlying the 75% net profits interest.

Unit operators of the properties underlying the 75% net
profits interests have reported total budgeted development costs, net to the underlying properties, of approximately $1.0 million for 2016 and $1.1 million for 2017, as compared to budgeted development costs of $4.4 million and actual development
costs of $2.7 million for 2015. 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. Changes in oil or natural gas prices could impact
future development plans on the underlying properties.

Other Proceeds

The calculation of net profits income for the year ended 2014 included $519,071 ($467,164 net to the Trust), which includes interest of $210,242
($189,218 net to the Trust), related to a one-time purchaser refund for deductions attributable to coal seam gas wells located in the San Juan Basin for the period December 1997 through May 2006.

Fourth Quarter 2015 and 2014

During the quarter ended
December 31, 2015, the Trust received net profits income totaling $2,314,162, compared with fourth quarter 2014 net profits income of $3,530,797. This 34% decrease is primarily attributable to lower oil and gas prices ($2.5 million), partially
offset by increased gas production ($0.6 million), lower development costs ($0.4 million) and excess costs on the Texas and Oklahoma working interest properties in 2015 ($0.2 million).

Administration expense was $248,788 and trust interest income was $12, resulting in fourth quarter 2015 distributable income of $2,065,386, or $0.344231
per unit. Administration expense for the quarter ended December 31, 2015 included $150,000 which the trustee reserved for administrative expenses. Distributable income for fourth quarter 2014 was $3,437,466, or $0.572911 per unit. Distributions
to unitholders for the quarter ended December 31, 2015 were:



|                  |  |                   |  |          |          | 
|----------------- |  | ----------------- |  | -------- | -------- | 
|Record Date       |  | Payment Date      |  | Per Unit |         
|October 30, 2015  |  | November 16, 2015 |  | $        | 0.102382 | 
|November 30, 2015 |  | December 14, 2015 |  |          | 0.126065 | 
|December 31, 2015 |  | January 15, 2016  |  |          | 0.115784 | 
|                  |  |                   |  |          |          | 
|                  |  |                   |  | $        | 0.344231 | 
|                  |  |                   |  |          |          | 

Volumes

Fourth
quarter 2015 underlying oil sales volumes were 56,619 Bbls, or 3% lower than 2014 levels and underlying gas sales volumes were 509,306 Mcf, or 39% higher than 2014 levels. Oil sales volumes decreased in 2015 primarily because of the timing of cash
receipts and natural production decline, partially offset by increased production from new wells and workovers. Gas sales volumes increased in 2015 primarily because of the timing of cash receipts, partially offset by natural production decline.

Prices

The average fourth quarter 2015 oil price
was $43.74 per Bbl, 49% lower than the fourth quarter 2014 average price of $86.61. The average fourth quarter 2015 gas price was $4.67 per Mcf, 25% lower than the fourth quarter 2014 average price of $6.19. For further information about oil and gas
prices, see Years Ended December 31, 2015, 2014 and 2013  Prices above.



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Costs

Costs deducted in the calculation of fourth quarter 2015 net profits income decreased $967,814, or 30%, from fourth quarter 2014. This decrease was
primarily related to lower development costs related to decreased development activity and costs on non-operated Texas and Oklahoma oil properties underlying the 75% net profits interest and excess costs on the Texas and Oklahoma working interest
properties in 2015. For further information about development and excess costs, see Years Ended December 31, 2015, 2014 and 2013  Costs above.

Liquidity and Capital Resources

The trusts only cash
requirement is the monthly distribution of its income to unitholders, which is funded by the monthly receipt of net profits income after payment of trust administration expenses. The Trust is not liable for any production costs or liabilities
attributable to the 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. The climate accord reached at the recent Conference of the
Parties (COP21) in Paris set many new goals, and while many related policies are still emerging, XTO Energy has informed the trustee that it continues to anticipate that such policies will increase the cost of carbon dioxide emissions over time. 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, 2015, other than the December distribution payable to unitholders in January 2016, as shown in the statement of assets, liabilities and trust
corpus.



|                                    |  |                        |         |  |                 |   |         |             |  |   |             |  |  |                  |   |  |  |   |   | 
|----------------------------------- |  | ---------------------- | ------- |  | --------------- | - | ------- | ----------- |  | - | ----------- |  |  | ---------------- | - |  |  | - | - | 
|                                    |  | Payments due by Period |        
|                                    |  | Total                  |         |  | Less than 1Year |   |         | 1 - 3 Years |  |   | 3 - 5 Years |  |  | More than5 Years |  
|Distribution payable to unitholders |  | $                      | 694,704 |  |                 | $ | 694,704 |             |  | $ |            |  |  | $                |  |  |  | $ |  | 

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,



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2015, this monthly charge was $38,430 ($28,823 net to the Trust). Included in this monthly overhead charge is a charge XTO Energy deducts as operator of the Hewitt Unit. As of December 31,
2015, monthly overhead attributable to the Hewitt Unit was $5,490 ($4,118 net to 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.

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.

Impairment

The trustee reviews the Trusts net profits interests (NPI) in oil and gas properties for impairment whenever events or circumstances
indicate that the carrying value of the NPI may not be recoverable.

In general, the trustee does not view temporarily low prices as a trigger event
for conducting an impairment test. The markets for crude oil and natural gas have a history of significant price volatility and though prices will occasionally drop significantly, industry prices over the long term will continue to be driven by
market supply and demand. If a trigger event occurred, the trustee would use the estimated undiscounted future net cash flows from the NPI to evaluate the recoverability of the Trust assets. If the undiscounted future net cash flows from the NPI are
less than the NPI carrying value, the Trust would recognize an impairment loss for the difference between the NPI carrying value and the estimated fair value of the NPI. The determination as to whether the NPI is impaired requires a significant
amount of judgment by the trustee and is based on the best information available to the trustee at the time of the evaluation.

In light of the
recent weakness in the industry environment, the trustee performed an assessment of the forecasted net cash flows for the NPI. Cash flows used in the assessment were developed using estimates for future crude oil and natural



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gas commodity prices published by third-party industry experts. Volumes and costs were based on assumptions developed in the XTO Energy annual planning and budgeting process which includes the
underlying properties from which the Trust NPI were conveyed. The result of the assessment confirmed no trigger event had occurred and that the undiscounted future net cash flows from the NPI exceeds the carrying value of the NPI. There was no
impairment of the assets as of December 31, 2015.

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.

When crude oil and natural gas prices are in the range seen in late 2015 and early 2016 for an extended period of time, under the SEC definition of
proved reserves, certain quantities of oil and natural gas may no longer qualify as proved reserves. Amounts required to be de-booked as proved reserves on an SEC basis are subject to being re-booked as proved reserves at some point in the future
when price levels recover.

The standardized measure of discounted future net cash flows and changes in such cash flows, as reported in Note 8 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, and year end costs for estimated future development and production expenditures. Discounted future net cash flows are calculated using a 10%
rate. Changes in any of these assumptions, including consideration of other factors, could have a significant impact on the standardized measure. Accordingly, the standardized measure does not represent XTO Energys or the trustees
estimated current market value of proved reserves.

Forward-Looking Statements

Certain information included in this annual report and other materials filed, or to be filed, by the Trust with the Securities and Exchange Commission
(as well as information included in oral statements or other written statements made or to be made by XTO Energy or the trustee) contain forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934, as
amended, and Section 27A of the Securities Act of 1933, as amended, relating to the trust, operations of the underlying properties and the oil and gas industry. Such forward-looking statements may concern, among other things, development
activities, future development plans, increased density drilling, 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 financial and operational 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



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exposed to market risk from fluctuations in oil and gas prices. A significant decline in oil or natural gas prices could have a material adverse effect on the amount of oil and natural gas that
is economic to produce, Trust net profits and proved reserves attributable to the Trusts interests. 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 |   
|Report of Independent Registered Public Accounting Firm |  |      | 27 | 
|Statements of Assets, Liabilities and Trust Corpus      |  |      | 28 | 
|Statements of Changes Distributable Income              |  |      | 28 | 
|Statements of Changes in Trust Corpus                   |  |      | 28 | 
|Notes to Financial Statements                           |  |      | 29 | 

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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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Unitholders of Cross Timbers Royalty Trust and

Southwest Bank, Trustee

We have audited the accompanying statements of assets, liabilities and trust corpus of Cross Timbers Royalty Trust (the Trust) as of
December 31, 2015 and 2014, and the related statements of distributable income and changes in trust corpus for each of the three years in the period ended December 31, 2015. We also have audited the Trusts internal control over
financial reporting as of December 31, 2015, based on criteria established in Internal ControlIntegrated Framework (2013)issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Trustee 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 Trustees Report on
Internal Control Over Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on these financial statements and on the Trusts internal control over financial reporting based on our integrated 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, 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.

A
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
generally accepted accounting principles. A trusts internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect
the transactions and dispositions of the assets of the trust; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting
principles, and that receipts and expenditures of the trust are being made only in accordance with authorizations of the trustee; and (iii) 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 the Trust at December 31, 2015 and 2014, and the distributable income and changes in trust corpus for each of the three years in the period ended
December 31, 2015, on the basis of accounting described in Note 2. Also in our opinion, the Trust maintained, in all material respects, effective internal control over financial reporting as of December 31, 2015, based on criteria
established in Internal ControlIntegrated Framework (2013) issued by COSO.

/s/ PricewaterhouseCoopers LLP

Dallas, Texas

March 11, 2016



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CROSS TIMBERS ROYALTY TRUST

STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS



|                                                                                 |  |             |            |  |      |   |            | 
|-------------------------------------------------------------------------------- |  | ----------- | ---------- |  | ---- | - | ---------- | 
|                                                                                 |  | December 31 |           
|                                                                                 |  | 2015        |            |  | 2014 |  
|Assets                                                                           |  |             |            |  |      |   |            | 
|Cash and short-term investments                                                  |  | $           | 969,700    |  |      | $ | 1,278,294  | 
|Interest to be received                                                          |  |             | 4          |  |      |   | 6          | 
|Net profits interests in oil and gas propertiesnet (Notes 1 and 2)              |  |             | 10,542,236 |  |      |   | 10,994,298 | 
|                                                                                 |  |             |            |  |      |   |            | 
|                                                                                 |  | $           | 11,511,940 |  |      | $ | 12,272,598 | 
|                                                                                 |  |             |            |  |      |   |            | 
|                                                                                 |  |            
|Liabilities and Trust Corpus                                                     |  |             |            |  |      |   |            | 
|Distribution payable to unitholders                                              |  | $           | 694,704    |  |      | $ | 1,278,300  | 
|Expense reserve(a)                                                               |  |             | 275,000    |  |      |   |           | 
|Trust corpus (6,000,000 units of beneficial interest authorized and outstanding) |  |             | 10,542,236 |  |      |   | 10,994,298 | 
|                                                                                 |  |             |            |  |      |   |            | 
|                                                                                 |  | $           | 11,511,940 |  |      | $ | 12,272,598 | 
|                                                                                 |  |             |            |  |      |   |            | 



|(a) | Expense reserve allows trustee to pay its obligations should it be unable to pay them out of the net profits income.
|--- | --------------------------------------------------------------------------------------------------------------------

STATEMENTS OF DISTRIBUTABLE INCOME



|                                                |  |                        |           |  |      |   |            |      |  |   |            | 
|----------------------------------------------- |  | ---------------------- | --------- |  | ---- | - | ---------- | ---- |  | - | ---------- | 
|                                                |  | Year Ended December 31 |          
|                                                |  | 2015                   |           |  | 2014 |   |            | 2013 | 
|Net profits income                              |  | $                      | 8,884,319 |  |      | $ | 16,449,036 |      |  | $ | 14,290,356 | 
|Interest income                                 |  |                        | 43        |  |      |   | 431        |      |  |   | 281        | 
|                                                |  |                        |           |  |      |   |            |      |  |   |            | 
|Total income                                    |  |                        | 8,884,362 |  |      |   | 16,449,467 |      |  |   | 14,290,637 | 
|Administration expense                          |  |                        | 755,694   |  |      |   | 504,167    |      |  |   | 403,043    | 
|                                                |  |                        |           |  |      |   |            |      |  |   |            | 
|Distributable income                            |  | $                      | 8,128,668 |  |      | $ | 15,945,300 |      |  | $ | 13,887,594 | 
|                                                |  |                        |           |  |      |   |            |      |  |   |            | 
|Distributable income per unit (6,000,000 units) |  | $                      | 1.354778  |  |      | $ | 2.657550   |      |  | $ | 2.314599   | 
|                                                |  |                        |           |  |      |   |            |      |  |   |            | 

STATEMENTS OF CHANGES IN TRUST CORPUS



|                                      |  |                        |            |   |      |   |             |      |  |   |             |  
|------------------------------------- |  | ---------------------- | ---------- | - | ---- | - | ----------- | ---- |  | - | ----------- | -
|                                      |  | Year Ended December 31 |           
|                                      |  | 2015                   |            |   | 2014 |   |             | 2013 | 
|Trust corpus, beginning of year       |  | $                      | 10,994,298 |   |      | $ | 11,791,689  |      |  | $ | 12,532,729  |  
|Amortization of net profits interests |  |                        | (452,062   | ) |      |   | (797,391    | )    |  |   | (741,040    | )
|Distributable income                  |  |                        | 8,128,668  |   |      |   | 15,945,300  |      |  |   | 13,887,594  |  
|Distributions declared                |  |                        | (8,128,668 | ) |      |   | (15,945,300 | )    |  |   | (13,887,594 | )
|                                      |  |                        |            |   |      |   |             |      |  |   |             |  
|Trust corpus, end of year             |  | $                      | 10,542,236 |   |      | $ | 10,994,298  |      |  | $ | 11,791,689  |  
|                                      |  |                        |            |   |      |   |             |      |  |   |             |  

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 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.

Southwest Bank is the trustee of the trust. 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 holders of 80% or more of the outstanding trust units, or upon trust termination, and any sale must be for cash with the proceeds
promptly distributed to the unitholders on the next declared distribution;
| | - |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | 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 holders of 80% or more of the outstanding trust units to terminate the Trust in accordance with provisions of the Trust indenture.
| | - |  | --------------------------------------------------------------------------------------------------------------------------------------------

U.S. Trust, Bank of America Private Wealth Management, a division of Bank of America, N.A., as trustee of the Cross Timbers Royalty Trust, announced
that at the special meeting of the trusts unitholders held on June 20, 2014, the unitholders of the Trust voted to approve the proposal to appoint Southwest Bank as successor trustee of the Trust effective August 29, 2014. References
to the trustee for periods prior to August 29, 2014 shall mean Bank of America, N.A., and for periods on or after August 29, 2014 shall mean Southwest Bank.

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.
| | - |  | -------------------------------------------------------------------------------------------------------------------------------------



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NOTES TO FINANCIAL STATEMENTS(Continued)



| |  |  | Distributions to unitholders are recorded when declared by the trustee (Note 3).
| | - |  | --------------------------------------------------------------------------------

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



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



| |  |  | 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 trustee reviews the Trusts net profits interests (NPI) in oil and gas properties for impairment whenever events or circumstances
indicate that the carrying value of the NPI may not be recoverable.

In general, the trustee does not view temporarily low prices as a trigger event
for conducting an impairment test. The markets for crude oil and natural gas have a history of significant price volatility and though prices will occasionally drop significantly, industry prices over the long term will continue to be driven by
market supply and demand. If a trigger event occurred, the trustee would use the estimated undiscounted future net cash flows from the NPI to evaluate the recoverability of the Trust assets. If the undiscounted future net cash flows from the NPI are
less than the NPI carrying value, the Trust would recognize an impairment loss for the difference between the NPI carrying value and the estimated fair value of the NPI.

The determination as to whether the NPI is impaired requires a significant amount of judgment by the trustee and is based on the best information
available to the trustee at the time of the evaluation. There was no impairment of the assets as of December 31, 2015.

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 $50,558,213 as of December 31, 2015 and $50,106,151 as of December 31,
2014.

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



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NOTES TO FINANCIAL STATEMENTS(Continued)



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 7).

4. Income Taxes

For federal income tax purposes, the Trust constitutes a fixed investment trust that is taxed as a grantor trust. A grantor trust is not subject to tax
at the Trust level. Accordingly, no provision for income taxes has been made in the financial statements. The unitholders 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 have been received or accrued by each unitholder at the time such income is received or accrued by the Trust and not when distributed by the trust.

All revenues from the Trust are from sources within Texas, Oklahoma or New Mexico. Because it distributes all of its net income to unitholders, the
Trust has not been taxed at the Trust level in New Mexico or Oklahoma. While the Trust has not owed tax, the trustee is required to file a return with Oklahoma reflecting the income and deductions of the Trust attributable to properties located in
that state, along with a schedule that includes information regarding distributions to unitholders. Texas does not impose a state income tax, so no part of the trusts income will be subject to income tax at the Trust level in Texas.

Each unitholder should consult his or her own tax advisor regarding income tax requirements, if any, applicable to such persons ownership of trust
units.

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 operates the Hewitt Unit, which is one of the properties underlying the Oklahoma 75% net profits interests. Other than this property, 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, 2015 was $38,430 per month, or $461,160 annually (net to the Trust of $345,870 annually). Included in this monthly overhead charge is a charge XTO Energy deducts as
operator of the Hewitt Unit. As of December 31, 2015, overhead attributable to the Hewitt Unit was $5,490 per month, or $65,880 annually (net to the Trust of $49,410 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.

6. Contingencies

Several states have enacted legislation
requiring state income tax withholding from nonresident recipients of oil and gas proceeds. After consultation with its tax counsel, the trustee believes that it is not required to withhold on payments



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NOTES TO FINANCIAL STATEMENTS(Continued)



made to the unitholders. However, regulations are subject to change by the various states, which could change this conclusion. Should amounts be withheld on payments made to the Trust or the
unitholders, distributions to the unitholders would be reduced by the required amount, subject to the filing of a claim for refund by the Trust or unitholders for such amount.

7. Excess Costs



|                                                |  |                         |         |  |       |   |           |       |  |   |           | 
|----------------------------------------------- |  | ----------------------- | ------- |  | ----- | - | --------- | ----- |  | - | --------- | 
|                                                |  | Conveyances(Underlying) |        
|                                                |  | TX WI                   |         |  | OK WI |   |           | Total | 
|Cumulative excess costs remaining at 12/31/14   |  | $                       | 53,971  |  |       | $ |          |       |  | $ | 53,971    | 
|Net excess costs for the quarter ended 3/31/15  |  |                         | 410,337 |  |       |   | 43,414    |       |  |   | 453,751   | 
|Net excess costs for the quarter ended 6/30/15  |  |                         | 310,588 |  |       |   | 807,158   |       |  |   | 1,117,746 | 
|Net excess costs for the quarter ended 9/30/15  |  |                         | 88,604  |  |       |   | 9,635     |       |  |   | 98,239    | 
|Net excess costs for the quarter ended 12/31/15 |  |                         | 95,651  |  |       |   | 206,713   |       |  |   | 302,364   | 
|                                                |  |                         |         |  |       |   |           |       |  |   |           | 
|Cumulative excess costs remaining at 12/31/15   |  | $                       | 959,151 |  |       | $ | 1,066,920 |       |  | $ | 2,026,071 | 
|                                                |  |                         |         |  |       |   |           |       |  |   |           | 

XTO Energy advised the trustee that lower oil prices resulted in net excess costs of $905,180 ($678,885 net to the
Trust) on properties underlying the Texas working interest for the year ended December 31, 2015. This includes net excess costs of $95,651 ($71,738 net to the Trust) for the quarter ended December 31, 2015. However, these excess costs did
not reduce net proceeds from the remaining conveyances.

XTO Energy advised the trustee that timing of cash receipts, lower oil prices and decreased
oil production resulted in net excess costs of $1,066,920 ($800,190 net to the Trust) on properties underlying the Oklahoma working interest for the year ended December 31, 2015. This includes net excess costs of $206,713 ($155,035 net to the
Trust) for the quarter ended December 31, 2015. However, these excess costs did not reduce net proceeds from the remaining conveyances.

XTO
Energy has advised the trustee that increased costs, lower oil prices and a missing purchaser payment for oil revenue resulted in net excess costs of $53,971 ($40,478 net to the Trust) on properties underlying the Texas working interest for the year
ended December 31, 2014. This included net excess costs of $54,087 ($40,565 net to the Trust) for the quarter ended December 31, 2014. However, these excess costs did not reduce net proceeds from the remaining conveyances.

XTO advised the trustee that timing of cash receipts caused costs to exceed revenues by a total of $166 ($125 net to the Trust) on properties underlying
the Oklahoma working interest for the year ended December 31, 2014. However, these excess costs did not reduce net proceeds from the remaining conveyances. XTO advised the trustee that increased oil production led to the full recovery of excess
costs, plus accrued interest, of $166 ($125 net to the Trust) for the year ended December 31, 2014.

Lower oil prices and increased costs
related to the timing of cash expenditures caused costs to exceed revenues by a total of $251,863 ($188,897 net to the Trust) on properties underlying the Texas working interest for the year ended December 31, 2013. However, these excess costs
did not reduce net proceeds from the remaining conveyances. Decreased costs and increased oil prices led to the full recovery of excess costs, plus accrued interest, of $253,268 ($189,951 net to the Trust) for the year ended December 31, 2013.

Cumulative excess costs remaining for the Texas and Oklahoma working interest conveyances as of December 31, 2015 totaled $2,026,071
($1,519,553 net to the Trust).



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NOTES TO FINANCIAL STATEMENTS(Continued)



8. 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.

When crude oil and natural gas prices are in the range seen in late 2015 and early 2016 for an extended period of time, under the SEC definition of
proved reserves, certain quantities of oil and natural gas may no longer qualify as proved reserves. Amounts required to be de-booked as proved reserves on an SEC basis are subject to being re-booked as proved reserves at some point in the future
when price levels recover.

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, and year end costs for estimated future development and production
expenditures to produce the proved reserves. 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.

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.

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).

Oil prices used to determine the standardized measure were based on average realized oil prices of $46.58 per Bbl in 2015, $88.53 per Bbl in 2014,
$91.03 per Bbl in 2013 and $87.77 per Bbl in 2012. The weighted average realized gas prices used to determine the standardized measure were $2.83 per Mcf in 2015, $5.82 per Mcf in 2014, $5.15 per Mcf in 2013 and $4.24 per Mcf in 2012.



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NOTES TO FINANCIAL STATEMENTS(Continued)



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, 2012            |  |                          | 488 |   |                          |  | 21,942 |           |  |  | 506      |   |  |           | 158  |   |          |  | 994   |           |  |  | 22,100   |   |  |  | 2,235  |   |  |  | 25,015 |  
|Extensions, additions and discoveries |  |                          | 30  |   |                          |  | 321    |           |  |  |         |   |  |           |     |   |          |  | 30    |           |  |  | 321      |   |  |  | 33     |   |  |  | 357    |  
|Revisions of prior estimates          |  |                          | 28  |   |                          |  | (290   | )         |  |  | 34       |   |  |           | 18   |   |          |  | 62    |           |  |  | (272     | ) |  |  | 242    |   |  |  | (159   | )
|Production                            |  |                          | (59 | ) |                          |  | (1,417 | )         |  |  | (27      | ) |  |           | (10  | ) |          |  | (86   | )         |  |  | (1,427   | ) |  |  | (208   | ) |  |  | (1,641 | )
|                                      |  |                          |     |   |                          |  |        |           |  |  |          |   |  |           |      |   |          |  |       |           |  |  |          |   |  |  |        |   |  |  |        |  
|Balance, December 31, 2013            |  |                          | 487 |   |                          |  | 20,556 |           |  |  | 513      |   |  |           | 166  |   |          |  | 1,000 |           |  |  | 20,722   |   |  |  | 2,302  |   |  |  | 23,572 |  
|Extensions, additions and discoveries |  |                          | 14  |   |                          |  | 499    |           |  |  | 17       |   |  |           | 5    |   |          |  | 31    |           |  |  | 504      |   |  |  | 91     |   |  |  | 576    |  
|Revisions of prior estimates          |  |                          | 16  |   |                          |  | 314    |           |  |  | 38       |   |  |           | 10   |   |          |  | 54    |           |  |  | 324      |   |  |  | 146    |   |  |  | 309    |  
|Production                            |  |                          | (63 | ) |                          |  | (1,458 | )         |  |  | (33      | ) |  |           | (6   | ) |          |  | (96   | )         |  |  | (1,464   | ) |  |  | (221   | ) |  |  | (1,629 | )
|                                      |  |                          |     |   |                          |  |        |           |  |  |          |   |  |           |      |   |          |  |       |           |  |  |          |   |  |  |        |   |  |  |        |  
|Balance, December 31, 2014            |  |                          | 454 |   |                          |  | 19,911 |           |  |  | 535      |   |  |           | 175  |   |          |  | 989   |           |  |  | 20,086   |   |  |  | 2,318  |   |  |  | 22,828 |  
|                                      |  |                          |     |   |                          |  |        |           |  |  |          |   |  |           |      |   |          |  |       |           |  |  |          |   |  |  |        |   |  |  |        |  
|Extensions, additions and discoveries |  |                          | 14  |   |                          |  | 142    |           |  |  |         |   |  |           |     |   |          |  | 14    |           |  |  | 142      |   |  |  | 16     |   |  |  | 158    |  
|Revisions of prior estimates          |  |                          | 25  |   |                          |  | (2,198 | )         |  |  | (477     | ) |  |           | (142 | ) |          |  | (452  | )         |  |  | (2,340   | ) |  |  | (1,264 | ) |  |  | (2,828 | )
|Production                            |  |                          | (65 | ) |                          |  | (1,409 | )         |  |  | (3       | ) |  |           |     |   |          |  | (68   | )         |  |  | (1,409   | ) |  |  | (232   | ) |  |  | (1,616 | )
|                                      |  |                          |     |   |                          |  |        |           |  |  |          |   |  |           |      |   |          |  |       |           |  |  |          |   |  |  |        |   |  |  |        |  
|Balance, December 31, 2015            |  |                          | 428 |   |                          |  | 16,446 |           |  |  | 55       |   |  |           | 33   |   |          |  | 483   |           |  |  | 16,479   |   |  |  | 838    |   |  |  | 18,542 |  
|                                      |  |                          |     |   |                          |  |        |           |  |  |          |   |  |           |      |   |          |  |       |           |  |  |          |   |  |  |        |   |  |  |        |  

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. Negative revisions for 2015 are primarily due to lower oil and gas prices.

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, 2012 |  |                          | 488 |  |                          |  | 21,942 |           |  |  | 506      |  |  |           | 158 |  |          |  | 994   |           |  |  | 22,100   |  |  |  | 2,235 |  |  |  | 25,015 | 
|                  |  |                          |     |  |                          |  |        |           |  |  |          |  |  |           |     |  |          |  |       |           |  |  |          |  |  |  |       |  |  |  |        | 
|December 31, 2013 |  |                          | 487 |  |                          |  | 20,556 |           |  |  | 513      |  |  |           | 166 |  |          |  | 1,000 |           |  |  | 20,722   |  |  |  | 2,302 |  |  |  | 23,572 | 
|                  |  |                          |     |  |                          |  |        |           |  |  |          |  |  |           |     |  |          |  |       |           |  |  |          |  |  |  |       |  |  |  |        | 
|December 31, 2014 |  |                          | 454 |  |                          |  | 19,911 |           |  |  | 535      |  |  |           | 175 |  |          |  | 989   |           |  |  | 20,086   |  |  |  | 2,318 |  |  |  | 22,828 | 
|                  |  |                          |     |  |                          |  |        |           |  |  |          |  |  |           |     |  |          |  |       |           |  |  |          |  |  |  |       |  |  |  |        | 
|December 31, 2015 |  |                          | 428 |  |                          |  | 16,446 |           |  |  | 55       |  |  |           | 33  |  |          |  | 483   |           |  |  | 16,479   |  |  |  | 838   |  |  |  | 18,542 | 
|                  |  |                          |     |  |                          |  |        |           |  |  |          |  |  |           |     |  |          |  |       |           |  |  |          |  |  |  |       |  |  |  |        | 



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CROSS TIMBERS ROYALTY TRUST

NOTES TO FINANCIAL STATEMENTS(Continued)



Standardized Measure of Discounted Future Net Cash Flows from Proved Reserves



|                        |  |                          |         |         |                          |   |         |             |   |   |         |          |   |      |       |   |      |   |         |      |  |   |         |   |  |      |         |   |  |   |         |   |  |   |         |  
|----------------------- |  | ------------------------ | ------- | ------- | ------------------------ | - | ------- | ----------- | - | - | ------- | -------- | - | ---- | ----- | - | ---- | - | ------- | ---- |  | - | ------- | - |  | ---- | ------- | - |  | - | ------- | - |  | - | ------- | -
|                        |  | 90% NetProfits Interests |         |         | 75% NetProfits Interests |   |         | Total       |  
|                        |  | December 31              |         |         | December 31              |   |         | December 31 |  
|(in thousands)          |  | 2015                     |         |         | 2014                     |   |         | 2013        |   |   | 2015    |          |   | 2014 |       |   | 2013 |   |         | 2015 |  |   | 2014    |   |  | 2013 |        
|Net Profits Interests   |  |                          |         |         |                          |   |         |             |   |   |         |          |   |      |       |   |      |   |         |      |  |   |         |   |  |      |         |   |  |   |         |   |  |   |         |  
|Future cash inflows     |  | $                        | 65,055  |         |                          | $ | 151,974 |             |   | $ | 149,640 |          |   | $    | 2,915 |   |      | $ | 49,733  |      |  | $ | 47,604  |   |  | $    | 67,970  |   |  | $ | 201,707 |   |  | $ | 197,244 |  
|Future production taxes |  |                          | (5,482  | )       |                          |   | (13,724 | )           |   |   | (13,466 | )        |   |      | (230  | ) |      |   | (3,732  | )    |  |   | (3,553  | ) |  |      | (5,712  | ) |  |   | (17,456 | ) |  |   | (17,019 | )
|                        |  |                          |         |         |                          |   |         |             |   |   |         |          |   |      |       |   |      |   |         |      |  |   |         |   |  |      |         |   |  |   |         |   |  |   |         |  
|Future net cash flows   |  |                          | 59,573  |         |                          |   | 138,250 |             |   |   | 136,174 |          |   |      | 2,685 |   |      |   | 46,001  |      |  |   | 44,051  |   |  |      | 62,258  |   |  |   | 184,251 |   |  |   | 180,225 |  
|10% discount factor     |  |                          | (27,789 | )       |                          |   | (68,986 | )           |   |   | (68,480 | )        |   |      | (727  | ) |      |   | (19,330 | )    |  |   | (19,151 | ) |  |      | (28,516 | ) |  |   | (88,316 | ) |  |   | (87,631 | )
|                        |  |                          |         |         |                          |   |         |             |   |   |         |          |   |      |       |   |      |   |         |      |  |   |         |   |  |      |         |   |  |   |         |   |  |   |         |  
|Standardized measure    |  | $                        | 31,784  |         |                          | $ | 69,264  |             |   | $ | 67,694  |          |   | $    | 1,958 |   |      | $ | 26,671  |      |  | $ | 24,900  |   |  | $    | 33,742  |   |  | $ | 95,935  |   |  | $ | 92,594  |  
|                        |  |                          |         |         |                          |   |         |             |   |   |         |          |   |      |       |   |      |   |         |      |  |   |         |   |  |      |         |   |  |   |         |   |  |   |         |  
|                        |  |                          |         |         |                          |   |         |             |  
|Underlying Properties   |  |                          |         |         |                          |   |         |             |   |   |         |          |   |      |       |   |      |   |         |      |  |   |         |   |  |      |         |   |  |   |         |   |  |   |         |  
|Future cash inflows     |  |                          | $       | 91,575  |                          |   | $       | 338,134     |   |   | $       | 330,927  |  
|Future costs            |  |                          |         | (21,803 | )                        |   |         | (123,191    | ) |   |         | (120,887 | )
|                        |  |                          |         |         |                          |   |         |             |   |   |         |          |   |      |       |   |      |   |         |      |  |   |         |   |  |      |         |   |  |   |         |   |  |   |         |  
|Future net cash flows   |  |                          |         | 69,772  |                          |   |         | 214,943     |   |   |         | 210,040  |  
|10% discount factor     |  |                          |         | (31,846 | )                        |   |         | (102,422    | ) |   |         | (101,624 | )
|                        |  |                          |         |         |                          |   |         |             |   |   |         |          |   |      |       |   |      |   |         |      |  |   |         |   |  |      |         |   |  |   |         |   |  |   |         |  
|Standardized measure    |  |                          | $       | 37,926  |                          |   | $       | 112,521     |   |   | $       | 108,416  |  
|                        |  |                          |         |         |                          |   |         |             |   |   |         |          |   |      |       |   |      |   |         |      |  |   |         |   |  |      |         |   |  |   |         |   |  |   |         |  

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



|                                                            |  |                          |         |         |                          |   |         |         |   |   |         |         |   |      |         |   |      |   |        |      |  |   |        |   |  |      |         |   |  |   |         |   |  |   |         |  
|----------------------------------------------------------- |  | ------------------------ | ------- | ------- | ------------------------ | - | ------- | ------- | - | - | ------- | ------- | - | ---- | ------- | - | ---- | - | ------ | ---- |  | - | ------ | - |  | ---- | ------- | - |  | - | ------- | - |  | - | ------- | -
|                                                            |  | 90% NetProfits Interests |         |         | 75% NetProfits Interests |   |         | Total   |  
|(in thousands)                                              |  | 2015                     |         |         | 2014                     |   |         | 2013    |   |   | 2015    |         |   | 2014 |         |   | 2013 |   |        | 2015 |  |   | 2014   |   |  | 2013 |        
|Net Profits Interests                                       |  |                          |         |         |                          |   |         |         |   |   |         |         |   |      |         |   |      |   |        |      |  |   |        |   |  |      |         |   |  |   |         |   |  |   |         |  
|Standardized measure, January 1                             |  | $                        | 69,264  |         |                          | $ | 67,694  |         |   | $ | 61,469  |         |   | $    | 26,671  |   |      | $ | 24,900 |      |  | $ | 23,463 |   |  | $    | 95,935  |   |  | $ | 92,594  |   |  | $ | 84,932  |  
|Extensions, additions and discoveries                       |  |                          | 634     |         |                          |   | 2,096   |         |   |   | 1,997   |         |   |      |        |   |      |   | 704    |      |  |   |       |   |  |      | 634     |   |  |   | 2,800   |   |  |   | 1,997   |  
|Accretion of discount                                       |  |                          | 5,864   |         |                          |   | 5,734   |         |   |   | 5,202   |         |   |      | 2,367   |   |      |   | 2,187  |      |  |   | 2,063  |   |  |      | 8,231   |   |  |   | 7,921   |   |  |   | 7,265   |  
|Revisions of prior estimates, changes in price    and other |  |                          | (35,307 | )       |                          |   | 7,297   |         |   |   | 10,967  |         |   |      | (26,866 | ) |      |   | 1,772  |      |  |   | 1,723  |   |  |      | (62,173 | ) |  |   | 9,069   |   |  |   | 12,690  |  
|Net profits income                                          |  |                          | (8,671  | )       |                          |   | (13,557 | )       |   |   | (11,941 | )       |   |      | (214    | ) |      |   | (2,892 | )    |  |   | (2,349 | ) |  |      | (8,885  | ) |  |   | (16,449 | ) |  |   | (14,290 | )
|                                                            |  |                          |         |         |                          |   |         |         |   |   |         |         |   |      |         |   |      |   |        |      |  |   |        |   |  |      |         |   |  |   |         |   |  |   |         |  
|Standardized measure, December 31                           |  | $                        | 31,784  |         |                          | $ | 69,264  |         |   | $ | 67,694  |         |   | $    | 1,958   |   |      | $ | 26,671 |      |  | $ | 24,900 |   |  | $    | 33,742  |   |  | $ | 95,935  |   |  | $ | 92,594  |  
|                                                            |  |                          |         |         |                          |   |         |         |   |   |         |         |   |      |         |   |      |   |        |      |  |   |        |   |  |      |         |   |  |   |         |   |  |   |         |  
|                                                            |  |                          |         |         |                          |   |         |         |  
|Underlying Properties                                       |  |                          |         |         |                          |   |         |         |   |   |         |         |   |      |         |   |      |   |        |      |  |   |        |   |  |      |         |   |  |   |         |   |  |   |         |  
|Standardized measure, January 1                             |  |                          | $       | 112,521 |                          |   | $       | 108,416 |   |   | $       | 99,583  |  
|                                                            |  |                          |         |         |                          |   |         |         |   |   |         |         |   |      |         |   |      |   |        |      |  |   |        |   |  |      |         |   |  |   |         |   |  |   |         |  
|Revisions:                                                  |  |                          |         |         |                          |   |         |         |   |   |         |         |  
|Prices and costs                                            |  |                          |         | (50,293 | )                        |   |         | 8,570   |   |   |         | 12,803  |  
|Quantity estimates                                          |  |                          |         | (24,841 | )                        |   |         | 5,777   |   |   |         | 5,170   |  
|Accretion of discount                                       |  |                          |         | 9,673   |                          |   |         | 9,285   |   |   |         | 8,530   |  
|Future development costs                                    |  |                          |         | (1,896  | )                        |   |         | (4,125  | ) |   |         | (3,481  | )
|Other                                                       |  |                          |         | 5       |                          |   |         | (15     | ) |   |         | (5      | )
|                                                            |  |                          |         |         |                          |   |         |         |   |   |         |         |   |      |         |   |      |   |        |      |  |   |        |   |  |      |         |   |  |   |         |   |  |   |         |  
|Net revisions                                               |  |                          |         | (67,352 | )                        |   |         | 19,492  |   |   |         | 23,017  |  
|Extensions, additions and discoveries                       |  |                          |         | 704     |                          |   |         | 3,268   |   |   |         | 2,218   |  
|Production                                                  |  |                          |         | (10,645 | )                        |   |         | (22,029 | ) |   |         | (19,883 | )
|Development costs                                           |  |                          |         | 2,698   |                          |   |         | 3,374   |   |   |         | 3,481   |  
|                                                            |  |                          |         |         |                          |   |         |         |   |   |         |         |   |      |         |   |      |   |        |      |  |   |        |   |  |      |         |   |  |   |         |   |  |   |         |  
|Net change                                                  |  |                          |         | (74,595 | )                        |   |         | 4,105   |   |   |         | 8,833   |  
|                                                            |  |                          |         |         |                          |   |         |         |   |   |         |         |   |      |         |   |      |   |        |      |  |   |        |   |  |      |         |   |  |   |         |   |  |   |         |  
|Standardized measure, December 31                           |  |                          | $       | 37,926  |                          |   | $       | 112,521 |   |   | $       | 108,416 |  
|                                                            |  |                          |         |         |                          |   |         |         |   |   |         |         |   |      |         |   |      |   |        |      |  |   |        |   |  |      |         |   |  |   |         |   |  |   |         |  



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CROSS TIMBERS ROYALTY TRUST

NOTES TO FINANCIAL STATEMENTS(Continued)



9. Quarterly Financial Data (Unaudited)

The following is a summary of net profits income, distributable income and distributable income per unit by quarter for 2015 and 2014:



|               |  |                   |            |  |                     |   |            |                             |  |   |          | 
|-------------- |  | ----------------- | ---------- |  | ------------------- | - | ---------- | --------------------------- |  | - | -------- | 
|               |  | Net ProfitsIncome |            |  | DistributableIncome |   |            | DistributableIncomeper Unit | 
|2015           |  |                   |            |  |                     |   |            |                             |  |   |          | 
|First Quarter  |  | $                 | 2,824,371  |  |                     | $ | 2,565,990  |                             |  | $ | 0.427665 | 
|Second Quarter |  |                   | 1,851,313  |  |                     |   | 1,736,628  |                             |  |   | 0.289438 | 
|Third Quarter  |  |                   | 1,894,473  |  |                     |   | 1,760,664  |                             |  |   | 0.293444 | 
|Fourth Quarter |  |                   | 2,314,162  |  |                     |   | 2,065,386  |                             |  |   | 0.344231 | 
|               |  |                   |            |  |                     |   |            |                             |  |   |          | 
|               |  | $                 | 8,884,319  |  |                     | $ | 8,128,668  |                             |  | $ | 1.354778 | 
|               |  |                   |            |  |                     |   |            |                             |  |   |          | 
|               |  |                   |           
|2014           |  |                   |            |  |                     |   |            |                             |  |   |          | 
|First Quarter  |  | $                 | 4,386,145  |  |                     | $ | 4,203,960  |                             |  | $ | 0.700660 | 
|Second Quarter |  |                   | 3,859,488  |  |                     |   | 3,766,254  |                             |  |   | 0.627709 | 
|Third Quarter  |  |                   | 4,672,606  |  |                     |   | 4,537,620  |                             |  |   | 0.756270 | 
|Fourth Quarter |  |                   | 3,530,797  |  |                     |   | 3,437,466  |                             |  |   | 0.572911 | 
|               |  |                   |            |  |                     |   |            |                             |  |   |          | 
|               |  | $                 | 16,449,036 |  |                     | $ | 15,945,300 |                             |  | $ | 2.657550 | 
|               |  |                   |            |  |                     |   |            |                             |  |   |          | 

10. Other Proceeds

The
calculation of net profits income for the year ended 2014 included $519,071 ($467,164 net to the Trust), which includes interest of $210,242 ($189,218 net to the Trust), related to a one-time purchaser refund for deductions attributable to coal seam
gas wells located in the San Juan Basin for the period December 1997 through May 2006.



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##### Table of Contents

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

None.



|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, Southwest Bank, 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 (2013) 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 (2013), the trustee concluded that the trusts internal control over financial reporting was effective as of December 31, 2015. The effectiveness of the trusts internal control over financial reporting as of
December 31, 2015 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report under Item 8, Financial Statements and Supplementary Data.

Changes in Internal Control Over Financial Reporting

There
were no changes in the trusts internal control over financial reporting during the quarter ended December 31, 2015 that have materially affected, or are reasonably likely to materially affect, the trusts internal control over
financial reporting.



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

None.



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##### Table of Contents

PART III



|Item 10. | Directors, Executive Officers and Corporate Governance
|-------- | ------------------------------------------------------

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

Section 16(a) of the Securities Exchange Act of 1934 requires that 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, 2015.

Because the Trust has no employees, it does not have a code of ethics. Employees of the trustee,
Southwest Bank, must comply with the banks standards of conduct, a copy of which will be made available to unitholders without charge, upon request by appointment at 2911 Turtle Creek Boulevard, Suite 850, Dallas, Texas, 75219.



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

The trustee received the following annual
compensation from 2013 through 2015 as specified in the Trust indenture:



|                                                                     |  |      |        |  |      |   |        |      |  |   |        | 
|-------------------------------------------------------------------- |  | ---- | ------ |  | ---- | - | ------ | ---- |  | - | ------ | 
|                                                                     |  | 2015 |        |  | 2014 |   |        | 2013 | 
|U.S. Trust, Bank of America Private Wealth Management, Trustee(1)(2) |  |      |       |  |      | $ | 20,315 |      |  | $ | 25,595 | 
|Southwest Bank, Trustee(1)(2)                                        |  | $    | 35,792 |  |      | $ | 25,024 |      |  |   |       | 



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



|(2) | Compensation for U.S. Trust is for the period January 2014 through August 2014 and compensation for Southwest Bank is for the period September 2014 through December 2014.
|--- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------



|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.

(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, 2015 was $38,430 per
month, or $461,160 annually (net to the Trust of $345,870 annually). Included in this monthly overhead charge is a charge XTO Energy deducts as operator of the Hewitt Unit. As of December 31, 2015 overhead attributable to the Hewitt Unit was
$5,490 per month, or $65,880 annually (net to the Trust of $49,410 annually). These overhead charges are subject to annual adjustment based on an oil and gas industry index.



38



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##### Table of Contents

See Item 11, Executive Compensation, for the remuneration received by the trustee from 2013 through
2015.

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
PricewaterhouseCoopers LLP for the years ended December 31, 2015 and 2014 are:



|                   |  |      |         |  |      |   |         | 
|------------------ |  | ---- | ------- |  | ---- | - | ------- | 
|                   |  | 2015 |         |  | 2014 |  
|Audit fees-PwC     |  |      | 126,670 |  |      |   | 125,600 | 
|Audit-related fees |  |      |        |  |      |   |        | 
|Tax fees           |  |      |        |  |      |   |        | 
|All other fees     |  |      |        |  |      |   |        | 
|                   |  |      |         |  |      |   |         | 
|                   |  | $    | 126,670 |  |      | $ | 125,600 | 
|                   |  |      |         |  |      |   |         | 

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 PricewaterhouseCoopers LLP.



39



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##### Table of Contents

PART IV



|Item 15. | Exhibits and Financial Statement Schedules
|-------- | ------------------------------------------



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



| | 1. | Financial Statements (included in Item 8 of this report)
| | -- | --------------------------------------------------------

Reports of Independent Registered
Public Accounting Firm

Statements of Assets, Liabilities and Trust Corpus at December 31, 2015 and 2014

Statements of Distributable Income for the years ended December 31, 2015, 2014 and 2013

Statements of Changes in Trust Corpus for the years ended December 31, 2015, 2014 and 2013

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., 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, 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.
| | --- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | (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, 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, 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, Southwest Bank, P.O. Box 962020, Fort Worth, Texas 76162-2020.



40



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##### Table of Contents

SIGNATURES

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



|                     |  |  |  |                             |  |                                          
|-------------------- |  |  |  | --------------------------- |  | -----------------------------------------
|                     |  |  |  | CROSS TIMBERS ROYALTY TRUST
|                     |  |  |  | By SOUTHWEST BANK, TRUSTEE 
|                     |  |  | 
|                     |  |  |  | By                          |  | /S/ NANCY G. WILLIS                      
|                     |  |  |  |                             |  | Nancy G. Willis                          
|                     |  |  |  |                             |  | Vice President                           
|                     |  | 
|                     |  |  |  | EXXON MOBIL CORPORATION    
|                     |  |  | 
|Date: March 11, 2016 |  |  |  | By                          |  | /S/ BETH E. CASTEEL                      
|                     |  |  |  |                             |  | Beth E. Casteel                          
|                     |  |  |  |                             |  | Vice PresidentUpstream Business Services

(The Trust has no directors or executive officers.)