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, 2016                         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  ☒

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  ☒

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  ☒        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.    ☒

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  ☒	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  ☒

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, 2016 (the last business day of its most recently completed second fiscal quarter), held by non-affiliates of the registrant on that date was approximately $108.8 million.

At February 15, 2017, 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

CROSS TIMBERS ROYALTY TRUST

2016 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		7
Item 2.	Properties		8
Item 3.	Legal Proceedings		16
Item 4.	Mine Safety Disclosures		16
PART II
Item 5.	Market for Units of the Trust, Related Unitholder Matters and Trust Purchases of Units		17
Item 6.	Selected Financial Data		17
Item 7.	Trustee’s Discussion and Analysis of Financial Condition and Results of Operations		18
Item 7A.	Quantitative and Qualitative Disclosures about Market Risk		24
Item 8.	Financial Statements and Supplementary Data		25
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		36
Item 9A.	Controls and Procedures		36
Item 9B.	Other Information		36
PART III
Item 10.	Directors, Executive Officers and Corporate Governance		37
Item 11.	Executive Compensation		37
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters		37
Item 13.	Certain Relationships and Related Transactions, and Director Independence		37
Item 14.	Principal Accountant Fees and Services		38
PART IV
Item 15.	Exhibits and Financial Statement Schedules		39

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)

BOE Barrel of oil equivalent

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 substantially all 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 overriding royalty 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 (the “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. On January 9, 2014, the successor of NCNB Texas National Bank, 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. 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).

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, 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, 2016 was $37,200 ($27,900 net to the Trust). XTO Energy deducts an overhead charge as operator of the Hewitt Unit. As of December 31, 2016, monthly overhead attributable to the Hewitt Unit was $5,314 ($3,986 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. For further information on excess costs, see Note 7 to Financial Statements under Item 8, Financial Statements and Supplementary Data.

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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 until the overpayment, plus interest at the prime rate, is recovered.

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 to 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 66% of the net profits income received by the Trust during 2016 was attributable to natural gas, as well as 64% of the Trust’s estimated future net cash flows from proved reserves at December 31, 2016 (based on estimated future net cash flows using 12-month average oil and gas prices, based on the first-day-of-the-month price for each month in the period). 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. Current market conditions are not necessarily indicative of future conditions.

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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 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, 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, the Trust will not receive net profits income for those properties until future net 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

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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 net profits 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 exposure to credit markets. The Trust’s future net profits, 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 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

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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 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

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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:

• reduced 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.

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. 13-16 and “Greenhouse Gas Emissions and Climate Change Regulations” on p. 21.

Item 1B. Unresolved Staff Comments

As of December 31, 2016, the Trust did not have any unresolved Securities and Exchange Commission staff comments.

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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, 2016 is approximately 9 years. This index is calculated using total proved reserves and estimated 2017 production for the underlying properties. The projected 2017 production is from proved developed producing reserves as of December 31, 2016. 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 future net cash flows from proved reserves of the underlying properties are approximately 64% natural gas and 36% oil. The underlying properties also include certain nonproducing properties in Texas, Oklahoma and New Mexico that are primarily mineral interests.

Producing Acreage, Wells and Drilling

90% Net Profits Interests Underlying Royalties.    Royalty and overriding royalty properties underlying the 90% net profits interests represent 90% of the discounted future net cash flows from Trust proved reserves at December 31, 2016. Approximately 71% of the discounted future net cash flows from the 90% net profits interests are from gas reserves, totaling 17.3 Bcf. Oil reserves allocated to the 90% net profits interests are primarily located in West Texas and are estimated to be 451,000 Bbls at December 31, 2016.

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 76% of the Trust’s gas sales volumes and 50% of the net profits income for 2016. The Trust’s estimated proved gas reserves from this region totaled 12.5 Bcf at December 31, 2016, or approximately 81% of Trust total gas reserves at that date. XTO Energy estimates that underlying royalties in the San Juan Basin include more than 4,960 gross (approximately 51.4 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

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• 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 280,798 gross (approximately 37,785 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, the net profits income from these properties is not reduced by production or development costs, with the exception of a limited number of wells that were converted to working interest after conveyance that incur production and 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 117,000 Bbls at year-end 2016. Proved reserves from these interests represent 10% of the discounted future net cash flows of the Trust’s proved reserves at December 31, 2016.

The underlying working interest properties are detailed below:

			Ownership of XTO Energy
Unit	County/State	Operator	Working Interest			Revenue Interest
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 (2,996 net) producing acres. As of December 31, 2016, there were 1,408 gross (70 net) productive oil wells and no wells in process of drilling on these properties. There were no wells drilled in 2016, 12 gross (1.0 net) wells drilled in 2015 and 5 gross (0.3 net) wells drilled in 2014.

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 2016 development costs were $998,200, down 63% from 2015 development costs of $2,697,664. Development costs were lower in 2016 because of decreased development activity and costs related to non-operated Texas and Oklahoma oil

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properties underlying the 75% net profits interest. January and February 2017 development costs totaled approximately $159,000, primarily incurred in fourth quarter 2016.

As reported to XTO Energy by unit operators in February of each year, budgeted development costs were $1.0 million for 2016 and $4.4 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. 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 $1.2 million for 2017 and $1.3 million for 2018. Changes in oil or natural gas prices could impact future development plans on the underlying properties.

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. Remaining cumulative excess costs totaled $2,403,654 ($1,802,741 net to the Trust) for the period ended December 31, 2016. For information regarding the effect of excess costs on Trust net profits income, see Note 7 to Financial Statements under Item 8, Financial Statements and Supplementary Data.

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, 2016:

	Underlying Properties				Net Profits Interests
	Proved Reserves(a)				Proved Reserves(a)(b)				Future Net Cash Flows from Proved Reserves(a)(c)
	Oil (Bbls)		Gas (Mcf)		Oil (Bbls)		Gas (Mcf)
(in thousands)									Undiscounted		Discounted
90% Net Profits Interests
San Juan Basin		18		13,896		16		12,507	$	26,448	$	14,011
Other New Mexico		30		92		27		82		1,293		646
Texas		353		1,972		318		1,777		17,214		9,464
Oklahoma		50		1,307		45		1,094		4,145		2,374
Total		451		17,267		406		15,460		49,100		26,495
75% Net Profits Interests
Texas		72		70		—		—		—		—
Oklahoma		720		180		117		29		4,155		2,889
Total		792		250		117		29		4,155		2,889
TOTAL		1,243		17,517		523		15,489	$	53,255	$	29,384

(a) Based on 12-month average oil price of $38.19 per Bbl and $2.45 per Mcf for gas, based on the first-day-of-the-month price for each month in the period.

(b) Since the Trust has defined net profits interests, the Trust does not own a specific percentage of the oil and gas reserves. Oil and gas reserves are allocated to the net profits interests by dividing Trust net cash inflows by 12-month average oil and gas prices. As such, reserves allocated to the Trust have been reduced to reflect recovery of the Trust’s portion of applicable production and development costs, which includes excess costs. Any conveyance where costs exceed revenues will result in zero allocated net profits interests reserves for that conveyance.

(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%.

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Proved reserves at December 31, 2016 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		1,243		17,517		523		15,489
Proved undeveloped reserves		—		—		—		—
Total proved reserves		1,243		17,517		523		15,489

The process of estimating oil and gas reserves is complex and requires significant judgment as discussed in Item 1A, Risk Factors, and is performed by XTO Energy. As a result, XTO Energy has developed internal policies and controls for estimating and recording reserves. XTO Energy’s policies regarding booking reserves require proved reserves to be in compliance with the SEC definitions and guidance. XTO Energy’s policies assign responsibilities for compliance in reserves bookings to its reserve engineering group and require that reserve estimates be made by qualified reserves estimators, as defined by the Society of Petroleum Engineers’ standards. All qualified reserves estimators are required to receive education covering the fundamentals of SEC proved reserves assignments.

The XTO Energy reserve engineering group reviews reserve estimates with 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, 2016, 2015, 2014 and 2013. Miller and Lents’ primary technical person responsible for calculating the Trust’s reserves has more than 25 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 underlying properties. Since the Trust has defined net profits interests, the Trust does not own a specific percentage of the oil and gas reserves. Oil and gas reserves are allocated to the net profits interests by dividing Trust net cash inflows by 12-month average oil and gas prices.

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 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 such, the underlying property production volume changes may not correlate with the Trust’s net profit share of those volumes in any given period.

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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
	2016		2015		2014		2016		2015		2014		2016		2015		2014
Production
Underlying Properties
Oil—Sales (Bbl)		66,487		77,221		72,101		157,801		154,836		149,286		224,288		232,057		221,387
Average per day (Bbls)		182		212		198		431		424		409		613		636		607
Gas—Sales (Mcf)		2,043,014		1,593,141		1,605,306		5,678		22,897		24,062		2,048,692		1,616,038		1,629,368
Average per day (Mcf)		5,582		4,365		4,398		16		63		66		5,598		4,428		4,464
Net Profits Interests
Oil—Sales (Bbls)		66,648		64,853		62,919		—		3,214		32,677		66,648		68,067		95,596
Average per day (Bbls)		182		178		172		—		9		90		182		187		262
Gas—Sales (Mcf)		1,895,526		1,409,136		1,458,575		—		175		5,732		1,895,526		1,409,311		1,464,307
Average per day (Mcf)		5,179		3,861		3,996		—		—		16		5,179		3,861		4,012
Average Sales Price
Oil (per Bbl)		$40.37		$58.44		$91.15		$37.02		$49.72		$91.64		$38.02		$52.62		$91.48
Gas (per Mcf)		$3.50		$4.49		$6.94		$19.61		$7.77		$11.21		$3.55		$4.54		$7.00
Average Production Cost per BOE(a)		$0.04		$0.05		$0.05		$29.47		$38.90		$37.42		$8.30		$12.34		$11.67

(a) Total average production cost per BOE includes production from the properties underlying the 90% net profits interests, which are substantially all royalty and overriding royalty interests with insignificant production costs.

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	2016			2015		2014
New Mexico royalty interest		1,594,530			1,008,064		1,111,622
Oklahoma royalty interest		266,551			349,439		276,549
Texas royalty interest		181,933			235,638		217,135
Texas working interest		12,935			14,939		11,490
Oklahoma working interest(b)		(7,257	)		7,958		12,572
Total		2,048,692			1,616,038		1,629,368

(b) Oklahoma working interest gas production for 2016 includes a one-time prior period revenue adjustment.

	Underlying Oil Production (Bbls)
Conveyance	2016		2015		2014
New Mexico royalty interest		5,855		5,672		6,382
Oklahoma royalty interest		17,686		22,075		14,914
Texas royalty interest		42,946		49,474		50,804
Texas working interest		56,151		60,133		57,928
Oklahoma working interest		101,650		94,703		91,359
Total		224,288		232,057		221,387

Nonproducing Acreage

The underlying nonproducing royalties contain approximately 227,000 gross (approximately 24,000 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.

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Pricing and Sales Information

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

Regulation

Natural Gas Regulation

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

Federal Regulation of Oil

Sales of crude oil, condensate and natural gas liquids are not currently regulated and are made at market prices. The net price received from the sale of these products is affected by market transportation costs. Under rules adopted by FERC effective January 1995, interstate oil pipelines can change rates based on an inflation index, though other rate mechanisms may be used in specific circumstances.

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

Environmental Regulation

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

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

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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 2016, the Trust incurred administration expenses and earned interest income on funds held for distribution and for the cash reserve maintained for the payment of contingent and future obligations of the Trust.

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 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

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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; (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; and (iv) items that constitute taxable income due to the recovery of prior period expense adjustments. Because of these types of items and when the trustee elects to reserve amounts from monthly distributions to maintain an administrative expense reserve, the taxable income per period frequently differs from the actual amount distributed to unitholders, including in 2016.

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, 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

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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 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 2016 and 2015:

	Sales Price				Distributions per Unit
Quarter	High		Low
2016
First	$	16.46	$	12.00	$	0.363497
Second		18.20		14.50		0.162530
Third		20.59		17.65		0.216652
Fourth		19.80		16.11		0.318121
					$	1.060800
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

At December 31, 2016, there were 6,000,000 units outstanding and approximately 220 unitholders of record; 5,854,606 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
	2016		2015		2014		2013		2012
Net Profits Income	$	7,541,706	$	8,884,319	$	16,449,036	$	14,290,356	$	15,283,504
Distributable Income		6,364,800		8,128,668		15,945,300		13,887,594		14,889,588
Distributable Income per Unit		1.060800		1.354778		2.657550		2.314599		2.481598
Distributions per Unit		1.060800		1.354778		2.657550		2.314599		2.481598
Total Assets at Year-End		11,448,234		11,511,940		12,272,598		12,935,109		13,840,567

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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 Ended December 31(a)
	2016			2015			2014			2016			2015
Sales Volumes
Oil (Bbls)(b)
Underlying properties		224,288			232,057			221,387			53,062			56,619
Average per day		613			636			607			577			615
Net profits interests		66,648			68,067			95,596			16,729			13,977
Gas (Mcf)(b)
Underlying properties		2,048,692			1,616,038			1,629,368			509,725			509,306
Average per day		5,598			4,428			4,464			5,540			5,536
Net profits interests		1,895,526			1,409,311			1,464,307			486,262			447,769
Average Sales Price
Oil (per Bbl)		$38.02			$52.62			$91.48			$42.16			$43.74
Gas (per Mcf)		$3.55			$4.54			$7.00			$3.45			$4.67
Revenues
Oil sales	$	8,526,335		$	12,211,006		$	20,251,792		$	2,237,209		$	2,476,400
Gas sales		7,268,081			7,337,579			11,413,196			1,757,270			2,379,549
Total Revenues		15,794,416			19,548,585			31,664,988			3,994,479			4,855,949
Costs
Taxes, transportation and other(e)		2,331,326			2,714,689			3,882,386			563,628			739,151
Production expense(c)		4,462,800			6,189,352			5,753,938			1,110,056			1,482,217
Development costs		998,200			2,697,664			3,373,537			237,045			365,653
Excess costs(d)		(377,583	)		(1,972,100	)		(53,971	)		(61,794	)		(302,364	)
Total Costs		7,414,743			9,629,605			12,955,890			1,848,935			2,284,657
Other Proceeds
Interest income(e)		—			—			210,242			—			—
Net Proceeds	$	8,379,673		$	9,918,980		$	18,919,340		$	2,145,544		$	2,571,292
Net Profits Income	$	7,541,706		$	8,884,319		$	16,449,036		$	1,930,990		$	2,314,162

(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 by dividing Trust net cash inflows by average sales prices. As oil and gas prices change, the Trust’s allocated production volumes are impacted as the quantity of production necessary to cover expenses changes inversely with price. As such, the underlying property production volume changes may not correlate with the Trust’s allocated production 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, 2016, this charge was $37,200 per month (including a monthly overhead charge of $5,314 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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Results of Operations

Years Ended December 31, 2016, 2015 and 2014

Net profits income for 2016 was $7,541,706 as compared with $8,884,319 for 2015 and $16,449,036 for 2014. The 15% decrease in net profits income from 2015 to 2016 was primarily because of lower oil and gas prices ($4.0 million), excess costs on the Texas and Oklahoma working interest properties in 2015 ($1.2 million) and decreased oil production ($0.3 million), partially offset by decreased production expenses ($1.3 million), lower development costs ($1.3 million), increased gas production ($1.2 million) and decreased taxes, transportation and other costs ($0.4 million). 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). During 2016, 2015 and 2014, 66%, 56% and 49%, respectively, of net profits income was derived from gas sales.

Trust administration expense was $475,015 in 2016 as compared to $480,694 in 2015 and $504,167 in 2014. Cash reserve activity was $725,000 in 2016 as compared to $275,000 in 2015, which the trustee reserved for administrative expenses. As of December 31, 2016, the reserve is fully funded at $1,000,000. Interest income was $23,109 in 2016, $43 in 2015 and $431 in 2014. Interest income in 2016 included $22,071 related to a prior period expense adjustment. Other changes in interest income are attributable to fluctuations in net profits income and interest rates.

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

• oil and gas sales volumes,

• oil and gas sales prices, and

• costs deducted in the calculation of net profits income.

Volumes

Oil.    Underlying oil sales volumes decreased 3% from 2015 to 2016 compared to a 5% increase from 2014 to 2015. Oil sales volumes in 2016 decreased from 2015 primarily because of natural production decline, partially offset by the timing of cash receipts. 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.

Gas. Underlying gas sales volumes increased 27% from 2015 to 2016 compared to a 1% decrease from 2014 to 2015. Gas sales volumes in 2016 increased from 2015 primarily because of the timing of cash receipts related to purchaser payments covering production back to 2013, partially offset by natural production decline. 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.

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 2016 was $38.02 per Bbl, a 28% decrease from the 2015 average oil price of $52.62, which was a 42% decrease from the 2014 average price of $91.48. Oil prices are expected to remain volatile. The average NYMEX price for November 2016 through January 2017 was $50.19 per Bbl. At March 1, 2017, the average NYMEX oil price for the following 12 months was $54.78 per Bbl.

Gas.    The 2016 average gas price was $3.55 per Mcf, a 22% decrease from the 2015 average gas price of $4.54, which was 35% lower than the 2014 average price of $7.00. Excluding the impact of the prior period production payments received in 2016, the adjusted gas price was $2.97 per Mcf. Natural gas prices are affected by natural gas liquids prices, 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

19

are expected to remain volatile. The average NYMEX price for fourth quarter 2016 was $2.98 per MMBtu. At March 1, 2017, the average NYMEX gas price for the following 12 months was $3.13 per MMBtu.

Costs

Because properties underlying the 90% net profits interests are primarily royalty and overriding royalty interests, the calculation of net profits income from these interests 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. For further information on excess costs, see Note 7 to Financial Statements under Item 8, Financial Statements and Supplementary Data.

Total costs deducted in the calculation of net profits income were $7.4 million in 2016, $9.6 million in 2015 and $13.0 million in 2014. The 23% decrease in costs from 2015 to 2016 is attributable to decreased production expense related to decreased outside operated costs, lower development costs related to decreased development activities and costs on non-operated Texas and Oklahoma oil properties underlying the 75% net profits interest, decreased oil and gas production taxes related to lower oil and gas revenues, partially offset by excess costs on the Texas and Oklahoma working interest properties in 2015 and increased other deductions related to increased gas production. 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 refund for coal seam gas deductions included in 2014 and increased production expense related to increased outside operated costs.

Unit operators of the properties underlying the 75% net profits interests have reported total budgeted development costs, net to the underlying properties, of approximately $1.2 million for 2017 and $1.3 million for 2018, as compared to budgeted development costs of $1.0 million and actual development costs of $1.0 million for 2016. 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 2016 and 2015

During the quarter ended December 31, 2016, the Trust received net profits income totaling $1,930,990, compared with fourth quarter 2015 net profits income of $2,314,162. This 17% decrease is primarily attributable to lower oil and gas prices ($0.6 million), excess costs on the Texas and Oklahoma working interest properties in 2015 ($0.2 million) and decreased oil production ($0.1 million), partially offset by lower production expenses ($0.3 million) and decreased taxes, transportation and other costs ($0.2 million).

Administration expense was $44,776 and Trust interest income was $22,512, resulting in fourth quarter 2016 distributable income of $1,908,726, or $0.318121 per unit. Interest income for the quarter ended December 31, 2016 included $22,071 related

20

to a prior period expense adjustment. Distributable income for fourth quarter 2015 was $2,065,386, or $0.344231 per unit. Distributions to unitholders for the quarter ended December 31, 2016 were:

Record Date	Payment Date	Per Unit
October 31, 2016	November 15, 2016	$	0.111170
November 30, 2016	December 14, 2016		0.116212
December 30, 2016	January 17, 2017		0.090739
		$	0.318121

Volumes

Fourth quarter 2016 underlying oil sales volumes were 53,062 Bbls, or 6% lower than 2015 levels primarily because of natural production decline. Underlying gas sales volumes for fourth quarter 2016 were 509,725 Mcf, relatively flat to 2015 levels as natural production decline was offset by the timing of cash receipts.

Prices

The average fourth quarter 2016 oil price was $42.16 per Bbl, 4% lower than the fourth quarter 2015 average price of $43.74. The average fourth quarter 2016 gas price was $3.45 per Mcf, 26% lower than the fourth quarter 2015 average price of $4.67. For further information about oil and gas prices, see “Years Ended December 31, 2016, 2015 and 2014 – Prices” above.

Costs

Costs deducted in the calculation of fourth quarter 2016 net profits income decreased $435,722, or 19%, from fourth quarter 2015. This decrease was primarily attributable to decreased production expense related to decreased outside operated costs, lower development costs related to decreased development activities and costs on non-operated Texas and Oklahoma oil properties underlying the 75% net profits interest, decreased oil and gas production taxes related to lower oil and gas revenues and decreased property taxes, partially offset by 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, 2016, 2015 and 2014 – 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 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.

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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, 2016, other than the December distribution payable to unitholders in January 2017, as shown in the statement of assets, liabilities and trust corpus.

	Payments due by Period
	Total		Less than 1 Year		1-3 Years		3-5 Years		More than 5 Years
Distribution payable to unitholders	$	544,434	$	544,434	$	—	$	—	$	—

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, 2016, this monthly charge was $37,200 ($27,900 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, 2016, monthly overhead attributable to the Hewitt Unit was $5,314 ($3,986 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.

22

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 an indication of impairment. 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 events and circumstances indicated that the carrying value may not be recoverable, 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, 2016.

Oil and Gas Reserves

The proved oil and gas reserves for the underlying properties are estimated by independent petroleum engineers. The estimated reserves for the underlying properties are then used by XTO Energy to calculate the estimated oil and gas reserves attributable to the net profits interests. Reserve engineering is a subjective process that is dependent upon the quality of available data and the interpretation thereof. Estimates by different engineers often vary, sometimes significantly. In addition, physical factors such as the results of drilling, testing and production subsequent to the date of an estimate, as well as economic factors such as changes in product prices, may justify revision of such estimates. Because proved reserves are required to be estimated using 12-month average prices, based on the first-day-of-the-month price for each month in the period, estimated reserve quantities can be significantly impacted by changes in product prices. Accordingly, oil and gas quantities ultimately recovered and the timing of production may be substantially different from original estimates.

The standardized measure of discounted future net cash flows and changes in such cash flows, as reported in Note 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, including recovery of cumulative excess costs remaining at year end. 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.

23

Item 7A. Quantitative and Qualitative Disclosures about Market Risk

The only assets of and sources of income to the Trust are the net profits interests, which generally entitle the Trust to receive a share of the net profits from oil and gas production from the underlying properties. Consequently, the Trust is exposed to market risk from fluctuations in oil and gas prices. 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. The Trust does not engage in transactions in foreign currencies which could expose the Trust to any foreign currency related market risk.

24

Item 8. Financial Statements and Supplementary Data

	Page
Report of Independent Registered Public Accounting Firm		26
Statements of Assets, Liabilities and Trust Corpus		27
Statements of Changes Distributable Income		27
Statements of Changes in Trust Corpus		27
Notes to Financial Statements		28

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.

25

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, 2016 and 2015, and the related statements of distributable income and changes in trust corpus for each of the three years in the period ended December 31, 2016. We also have audited the Trust’s internal control over financial reporting as of December 31, 2016, 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, 2016 and 2015, and the distributable income and changes in trust corpus for each of the three years in the period ended December 31, 2016, 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, 2016, based on criteria established in Internal Control—Integrated Framework (2013) issued by COSO.

/s/ PricewaterhouseCoopers LLP

Dallas, Texas

March 10, 2017

26

CROSS TIMBERS ROYALTY TRUST

STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS

	December 31
	2016		2015
Assets
Cash and short-term investments	$	1,544,252	$	969,700
Interest to be received		182		4
Net profits interests in oil and gas properties—net (Notes 1 and 2)		9,903,800		10,542,236
	$	11,448,234	$	11,511,940
Liabilities and Trust Corpus
Distribution payable to unitholders	$	544,434	$	694,704
Expense reserve(a)		1,000,000		275,000
Trust corpus (6,000,000 units of beneficial interest authorized and outstanding)		9,903,800		10,542,236
	$	11,448,234	$	11,511,940

(a) Expense reserve allows trustee to pay its obligations should it be unable to pay them out of the net profits income. The reserve is fully funded at $1,000,000.

STATEMENTS OF DISTRIBUTABLE INCOME

	Year Ended December 31
	2016		2015		2014
Net profits income	$	7,541,706	$	8,884,319	$	16,449,036
Interest income(a)		23,109		43		431
Total income		7,564,815		8,884,362		16,449,467
Administration expense		475,015		480,694		504,167
Cash reserves withheld for Trust expenses		725,000		275,000		—
Distributable income	$	6,364,800	$	8,128,668	$	15,945,300
Distributable income per unit (6,000,000 units)	$	1.060800	$	1.354778	$	2.657550

(a) Interest income for the period ended December 31, 2016 includes $22,071 related to a prior period expense adjustment.

STATEMENTS OF CHANGES IN TRUST CORPUS

	Year Ended December 31
	2016			2015			2014
Trust corpus, beginning of year	$	10,542,236		$	10,994,298		$	11,791,689
Amortization of net profits interests		(638,436	)		(452,062	)		(797,391	)
Distributable income		6,364,800			8,128,668			15,945,300
Distributions declared		(6,364,800	)		(8,128,668	)		(15,945,300	)
Trust corpus, end of year	$	9,903,800		$	10,542,236		$	10,994,298

See accompanying notes to financial statements.

27

CROSS TIMBERS ROYALTY TRUST

NOTES TO FINANCIAL STATEMENTS

1. Trust Organization and Provisions

Cross Timbers Royalty Trust (the “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.

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

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CROSS TIMBERS ROYALTY TRUST

NOTES TO FINANCIAL STATEMENTS—(Continued)

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 an indication of impairment. 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 events and circumstances indicated the carrying value may not be recoverable, 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, 2016.

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 $51,196,649 as of December 31, 2016 and $50,558,213 as of December 31, 2015.

3. Distributions to Unitholders

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

Net profits income received by the trustee consists of net proceeds received in the prior month by XTO Energy from the underlying properties multiplied by the net profits percentage of 90% or 75%. Net proceeds are the gross proceeds received from the sale of production, less applicable costs. For the 90% net profits interests, such costs generally include production and property taxes, legal costs, and marketing and transportation charges. In addition to these costs, the 75% net profits interests include deductions for production expense and development costs.

29

CROSS TIMBERS ROYALTY TRUST

NOTES TO FINANCIAL STATEMENTS—(Continued)

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, 2016 was $37,200 per month, or $446,400 annually (net to the Trust of $334,800 annually). Included in this monthly overhead charge is a charge XTO Energy deducts as operator of the Hewitt Unit. As of December 31, 2016, overhead attributable to the Hewitt Unit was $5,314 per month, or $63,768 annually (net to the Trust of $47,826 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 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.

30

CROSS TIMBERS ROYALTY TRUST

NOTES TO FINANCIAL STATEMENTS—(Continued)

7. Excess Costs

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 proceeds from other conveyances.

	Conveyances (Underlying)
	TX WI		OK WI			Total
Cumulative excess costs remaining at 12/31/15	$	959,151	$	1,066,920		$	2,026,071
Net excess costs for the quarter ended 3/31/16		392,377		115,984			508,361
Net excess costs (recovery) for the quarter ended 6/30/16		163,954		(63,820	)		100,134
Net excess costs (recovery) for the quarter ended 9/30/16		23,597		(316,303	)		(292,706	)
Net excess costs (recovery) for the quarter ended 12/31/16		208,740		(146,946	)		61,794
Cumulative excess costs remaining at 12/31/16	$	1,747,819	$	655,835		$	2,403,654

XTO Energy advised the trustee that continued lower oil prices resulted in net excess costs of $788,668 ($591,501 net to the Trust) on properties underlying the Texas working interest for the year ended December 31, 2016. This includes net excess costs of $208,740 ($156,555 net to the Trust) for the quarter ended December 31, 2016.

XTO Energy advised the trustee that improved oil prices and decreased costs resulted in the partial recovery of excess costs of $411,085 ($308,314 net to the Trust) on properties underlying the Oklahoma working interest for the year ended December 31, 2016. This includes the partial recovery of $146,946 ($110,209 net to the Trust) for the quarter ended December 31, 2016.

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.

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.

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.

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. 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.

Cumulative excess costs remaining for the Texas and Oklahoma working interest conveyances as of December 31, 2016 totaled $2,403,654 ($1,802,741 net to the Trust).

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

31

CROSS TIMBERS ROYALTY TRUST

NOTES TO FINANCIAL STATEMENTS—(Continued)

economically producible from a given date forward, from known reservoirs and under existing economic conditions, operating methods, and government regulation before the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain. Proved developed reserves are the quantities expected to be recovered through existing wells with existing equipment and operating methods in which the cost of the required equipment is relatively minor compared with the cost of a new well. Due to the inherent uncertainties and the limited nature of reservoir data, such estimates are subject to change as additional information becomes available. The reserves actually recovered and the timing of production of these reserves may be substantially different from the original estimate. Revisions result primarily from new information obtained from development drilling and production history and from changes in economic factors.

Standardized Measure

The standardized measure of discounted future net cash flows and changes in such cash flows are prepared using assumptions required by the Financial Accounting Standards Board. Such assumptions include the use of 12-month average prices for oil and gas, based on the first-day-of-the-month price for each month in the period, and year end costs for estimated future development and production expenditures to produce the proved reserves, including recovery of cumulative excess costs remaining at year end. 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 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 $38.19 per Bbl in 2016, $46.58 per Bbl in 2015, $88.53 per Bbl in 2014 and $91.03 per Bbl in 2013. The weighted average realized gas prices used to determine the standardized measure were $2.45 per Mcf in 2016, $2.83 per Mcf in 2015, $5.82 per Mcf in 2014 and $5.15 per Mcf in 2013.

Reserve quantities and revenues for the net profits interests were estimated from projections of reserves and revenues attributable to the underlying properties. Since the Trust has defined net profits interests, the Trust does not own a specific percentage of the oil and gas reserves. Oil and gas reserves are allocated to the net profits interests by dividing Trust net cash inflows by 12-month average oil and gas prices. Any fluctuations in 12-month average prices or estimated costs will result in revisions to the estimated reserve quantities allocated to the net profits interests, which may not correlate with revisions of underlying proved reserves.

32

CROSS TIMBERS ROYALTY TRUST

NOTES TO FINANCIAL STATEMENTS—(Continued)

Proved Reserves

	Net Profits Interests																		Underlying Properties
	90% Net Profits Interests						75% Net Profits Interests						Total
(in thousands)	Oil (Bbls)			Gas (Mcf)			Oil (Bbls)			Gas (Mcf)			Oil (Bbls)			Gas (Mcf)			Oil (Bbls)			Gas (Mcf)
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		6			110			—			—			6			110			7			122
Revisions of prior estimates		38			800			62			(4	)		100			796			622			902
Production		(66	)		(1,896	)		—			—			(66	)		(1,896	)		(224	)		(2,049	)
Balance, December 31, 2016		406			15,460			117			29			523			15,489			1,243			17,517

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 the underlying properties in 2015 are primarily due to lower oil and gas prices. Positive revisions for the underlying properties in 2016 are primarily due to lower operating costs.

Proved Developed Reserves

	Net Profits Interests												Underlying Properties
	90% Net Profits Interests				75% Net Profits Interests				Total
(in thousands)	Oil (Bbls)		Gas (Mcf)		Oil (Bbls)		Gas (Mcf)		Oil (Bbls)		Gas (Mcf)		Oil (Bbls)		Gas (Mcf)
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
December 31, 2016		406		15,460		117		29		523		15,489		1,243		17,517

33

CROSS TIMBERS ROYALTY TRUST

NOTES TO FINANCIAL STATEMENTS—(Continued)

Standardized Measure of Discounted Future Net Cash Flows from Proved Reserves

	90% Net Profits Interests									75% Net Profits Interests									Total
	December 31									December 31									December 31
(in thousands)	2016			2015			2014			2016			2015			2014			2016			2015			2014
Net Profits Interests
Future cash inflows	$	53,629		$	65,055		$	151,974		$	4,477		$	2,915		$	49,733		$	58,106		$	67,970		$	201,707
Future production taxes		(4,529	)		(5,482	)		(13,724	)		(322	)		(230	)		(3,732	)		(4,851	)		(5,712	)		(17,456	)
Future net cash flows		49,100			59,573			138,250			4,155			2,685			46,001			53,255			62,258			184,251
10% discount factor		(22,605	)		(27,789	)		(68,986	)		(1,266	)		(727	)		(19,330	)		(23,871	)		(28,516	)		(88,316	)
Standardized measure	$	26,495		$	31,784		$	69,264		$	2,889		$	1,958		$	26,671		$	29,384		$	33,742		$	95,935
Underlying Properties
Future cash inflows																			$	90,456		$	91,575		$	338,134
Future costs																				(30,362	)		(21,803	)		(123,191	)
Future net cash flows																				60,094			69,772			214,943
10% discount factor																				(26,805	)		(31,846	)		(102,422	)
Standardized measure																			$	33,289		$	37,926		$	112,521

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

	90% Net Profits Interests									75% Net Profits Interests								Total
(in thousands)	2016			2015			2014			2016		2015			2014			2016			2015			2014
Net Profits Interests
Standardized measure, January 1	$	31,784		$	69,264		$	67,694		$	1,958	$	26,671		$	24,900		$	33,742		$	95,935		$	92,594
Extensions, additions and discoveries		290			634			2,096			—		—			704			290			634			2,800
Accretion of discount		2,719			5,864			5,734			174		2,367			2,187			2,893			8,231			7,921
Revisions of prior estimates,changes in price and other		(756	)		(35,307	)		7,297			757		(26,866	)		1,772			1			(62,173	)		9,069
Net profits income		(7,542	)		(8,671	)		(13,557	)		—		(214	)		(2,892	)		(7,542	)		(8,885	)		(16,449	)
Standardized measure, December 31	$	26,495		$	31,784		$	69,264		$	2,889	$	1,958		$	26,671		$	29,384		$	33,742		$	95,935
Underlying Properties
Standardized measure, January 1																		$	37,926		$	112,521		$	108,416
Revisions:
Prices and costs																			(11,714	)		(50,293	)		8,570
Quantity estimates																			12,511			(24,841	)		5,777
Accretion of discount																			3,252			9,673			9,285
Future development costs																			(998	)		(1,896	)		(4,125	)
Other																			(8	)		5			(15	)
Net revisions																			3,043			(67,352	)		19,492
Extensions, additions and discoveries																			322			704			3,268
Production																			(9,000	)		(10,645	)		(22,029	)
Development costs																			998			2,698			3,374
Net change																			(4,637	)		(74,595	)		4,105
Standardized measure, December 31																		$	33,289		$	37,926		$	112,521

34

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 2016 and 2015:

	Net Profits Income		Distributable Income		Distributable Income per Unit
2016
First Quarter	$	2,706,106	$	2,180,982	$	0.363497
Second Quarter		1,391,073		975,180		0.162530
Third Quarter		1,513,537		1,299,912		0.216652
Fourth Quarter		1,930,990		1,908,726		0.318121
	$	7,541,706	$	6,364,800	$	1.060800
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

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.

35

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, 2016. The effectiveness of the Trust’s internal control over financial reporting as of December 31, 2016 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, 2016 that have materially affected, or are reasonably likely to materially affect, the Trust’s internal control over financial reporting.

Item 9B. Other Information

None.

36

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, 2016.

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 2014 through 2016 as specified in the Trust indenture:

	2016		2015		2014
U.S. Trust, Bank of America Private Wealth Management, Trustee(1)(2)		—		—	$	20,315
Southwest Bank, Trustee(1)(2)	$	32,437	$	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, 2016 was $37,200 per month, or $446,400 annually (net to the Trust of $334,800 annually). Included in this monthly overhead charge is a charge XTO Energy deducts as operator of the Hewitt Unit. As of December 31, 2016 overhead attributable to the Hewitt Unit was $5,314 per month, or $63,768 annually (net to the Trust of $47,826 annually). These overhead charges are subject to annual adjustment based on an oil and gas industry index.

37

See Item 11, Executive Compensation, for the remuneration received by the trustee from 2014 through 2016.

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, 2016 and 2015 are:

	2016		2015
Audit fees-PwC		132,129		126,670
Audit-related fees		—		—
Tax fees		—		—
All other fees		—		—
	$	132,129	$	126,670

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.

38

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, 2016 and 2015

Statements of Distributable Income for the years ended December 31, 2016, 2015 and 2014

Statements of Changes in Trust Corpus for the years ended December 31, 2016, 2015 and 2014

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.

39

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 10, 2017	By	/s/ BETH E. CASTEEL
		Beth E. Casteel
		Vice President—Upstream Business Services

(The Trust has no directors or executive officers.)