CROSS TIMBERS ROYALTY TRUST - FORM 10-K

Attached files

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EX-32 - SECTION 1350 CERTIFICATION - CROSS TIMBERS ROYALTY TRUST	d303510dex32.htm
EX-31 - RULE 13A-14(A)/15D-14(A) CERTIFICATION - CROSS TIMBERS ROYALTY TRUST	d303510dex31.htm
EX-99.1 - MILLER AND LENTS, LTD. REPORT - CROSS TIMBERS ROYALTY TRUST	d303510dex991.htm

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, 2011		Commission file number 1-10982

Cross Timbers Royalty Trust

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

Texas

75-6415930

(State or other jurisdiction of

incorporation or organization)

(I.R.S. Employer

Identification No.)


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

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

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


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

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

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ¨ No x

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

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ¨ No ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. x

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


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

Indicate by check mark whether the registrant is a shell company (as defined in Exchange Act Rule 12b-2). Yes ¨ No x

The aggregate market value of the units of beneficial interest of the trust, based on the closing price on the New York Stock Exchange as of June 30, 2011 (the last business day of its most recently completed second fiscal quarter), held by non-affiliates of the registrant on that date was approximately $268 million.

At February 16, 2012, 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 TIMBER ROYALTY TRUST

2011 ANNUAL REPORT ON FORM 10-K

TABLE OF CONTENTS


		Page
	Glossary of Terms		1
Part I
Item 1.	Business		2
Item 1A.	Risk Factors		4
Item 1B.	Unresolved Staff Comments		8
Item 2.	Properties		8
Item 3.	Legal Proceedings		17
Item 4.	Mine Safety Disclosures		17
Part II
Item 5.	Market for Units of the Trust, Related Unitholder Matters and Trust Purchases of Units		18
Item 6.	Selected Financial Data		18
Item 7.	Trustee’s Discussion and Analysis of Financial Condition and Results of Operations		19
Item 7A.	Quantitative and Qualitative Disclosures about Market Risk		25
Item 8.	Financial Statements and Supplementary Data		25
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		39
Item 9A.	Controls and Procedures		39
Item 9B.	Other Information		39
Part III
Item 10.	Directors, Executive Officers and Corporate Governance		40
Item 11.	Executive Compensation		40
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters		40
Item 13.	Certain Relationships and Related Transactions, and Director Independence		41
Item 14.	Principal Accountant Fees and Services		41
Part IV
Item 15.	Exhibits and Financial Statement Schedules		42

Glossary of Terms

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

GLOSSARY



Bbl		Barrel (of oil)

Bcf		Billion cubic feet (of natural gas)

Mcf		Thousand cubic feet (of natural gas)

MMBtu		One million British Thermal Units, a common energy measurement

net proceeds		Gross proceeds received by XTO Energy from sale of production from the underlying properties, less applicable costs, as defined in the net profits interest conveyances

net profits income		Net proceeds multiplied by the applicable net profits percentage of 75% or 90%, which is paid to the trust by XTO Energy. “Net profits income” is referred to as “royalty income” for income tax purposes.

net profits interest		An interest in an oil and gas property measured by net profits from the sale of production, rather than a specific portion of production. The following defined net profits interests were conveyed to the trust from the underlying properties:

		90% net profits interests —interests that entitle the trust to receive 90% of the net proceeds from the underlying properties that are royalty or overriding royalty interests in Texas, Oklahoma and New Mexico

		75% net profits interests—interests that entitle the trust to receive 75% of the net proceeds from the underlying properties that are working interests in Texas and Oklahoma

royalty interest (and 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

PART I

Item 1.

Business

Cross Timbers Royalty Trust is an express trust created under the laws of Texas pursuant to the Cross Timbers Royalty Trust Indenture entered into on February 12, 1991 between predecessors of XTO Energy Inc. (formerly known as Cross Timbers Oil Company), as grantors, and NCNB Texas National Bank, as trustee. Bank of America, N.A. is now the trustee of the trust. In 2007 the Bank of America private wealth management group officially became known as “U.S. Trust, Bank of America Private Wealth Management.” The legal entity that serves as the trustee of the trust did not change, and references in this Form 10-K to U.S. Trust, Bank of America Private Wealth Management shall describe the legal entity Bank of America, N.A. The principal office of the trust is located at 901 Main Street, Dallas, Texas 75202 (telephone number 877-228-5084).

The trust’s internet web site is www.crosstimberstrust.com. We make available free of charge, through our web site, our Annual Report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and all amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934. These reports are accessible through our internet web site as soon as reasonably practicable after we electronically file such material with, or furnish it to, the Securities and Exchange Commission.

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

—

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

—

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

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

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

On June 25, 2010, XTO Energy became a wholly owned subsidiary of Exxon Mobil Corporation.

Under the terms of each of the five conveyances, the trust receives net profits income from the net profits interests generally on the last business day of each month. Net profits income is determined by XTO Energy by multiplying the net profit percentage (90% or 75%) times net proceeds from the underlying properties for each conveyance during the previous month. Net proceeds are the gross proceeds received from the sale of production, less “production costs”, as defined in the conveyances. For the 90% net profits interests and the 75% net profits interests, production costs generally include applicable property taxes, transportation, marketing and other charges. For the 75% net profits interests only, production costs also include capital and operating costs paid (e.g., drilling, production and other direct costs of owning and operating the property) and a monthly overhead charge that is adjusted annually. The monthly overhead charge at December 31, 2011 was $34,202 ($25,652 net to the trust). XTO Energy also deducts an overhead charge as operator of the Penwell Unit and ExxonMobil deducts an overhead charge as operator of the Hewitt Unit. As of December 31, 2011, monthly overhead attributable to the Penwell Unit was $2,656 ($1,992 net to the trust) and monthly overhead attributable to the Hewitt Unit was $4,507 ($3,380 net to the trust). If production costs exceed gross proceeds for any conveyance, this excess is carried forward to future monthly computations of net proceeds until the excess costs (plus interest accrued as specified in the conveyances) are completely recovered. Excess production costs and related accrued interest from one conveyance cannot be used to reduce net proceeds from any other conveyance.

Costs exceeded revenues on properties underlying the Texas working interest for January through April 2009 and on properties underlying the Oklahoma working interest for February through April 2009. There were no excess costs at December 31, 2011. For further information on excess costs, see Trustee’s Discussion and Analysis of Financial Condition and Results of Operations, under Item 7.

The trust is not liable for any production costs or liabilities attributable to the underlying properties. If at any time the trust receives net profits income in excess of the amount due, the trust is not obligated to return the overpayment, but net profits income payable to the trust for the next month will be reduced by the overpayment, plus interest at the prime rate.

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

As a working interest owner, XTO Energy can generally decline participation in any operation and allow consenting parties to conduct such operations, as provided under the operating agreements. XTO Energy also can assign, sell, or otherwise transfer its interest in the underlying properties, subject to the net profits interests, or can abandon an underlying property that is a working interest if it is incapable of producing in paying quantities, as determined by XTO Energy.

To the extent allowed, XTO Energy is responsible for marketing its production from the underlying properties under existing sales contracts or new arrangements on the best terms reasonably obtainable in the circumstances.

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

Adding—

(1)

net profits income received,

(2)

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

(3)

cash available as a result of reduction of cash reserves, and

(4)

other cash receipts, then

Subtracting—

(1)

liabilities paid and

(2)

the reduction in cash available due to establishment of or increase in any cash reserve.

The monthly distribution amount is distributed to unitholders of record within ten business days after the monthly record date. The monthly record date is generally the last business day of the month. The trustee calculates the monthly distribution amount and announces the distribution per unit at least ten days prior to the monthly record date.

The trustee may establish cash reserves for contingencies. Cash held for such reserves, as well as for pending payment of the monthly distribution amount may be invested in federal obligations or certificates of deposit of major banks.

The trustee’s function is to collect the net profits income from the net profits interests, to pay all trust expenses and pay the monthly distribution amount to unitholders. The trustee’s powers are specified by the terms of the indenture. The trust cannot engage in any business activity or acquire any assets other than the net profits interests and specific short-term cash investments. The trust has no employees since all administrative functions are performed by the trustee.

Approximately 52% of the net profits income received by the trust during 2011, as well as 60% of the estimated proved reserves of the net profits interests at December 31, 2011 (based on estimated future net cash flows using 12-month average oil and gas prices, based on the first-day-of-the-month price for each month in the period), is attributable to natural gas. There is generally a greater demand for gas during the winter. Otherwise, trust income is not subject to seasonal factors, nor dependent upon patents, licenses, franchises or concessions. The trust conducts no research activities.

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

Item 1A.

Risk Factors

The following factors could cause actual results to differ materially from those contained in forward-looking statements made in this report and presented elsewhere by the trustee from time to time. Such factors may have a material adverse effect upon the trust’s financial condition, distributable income and changes in trust corpus.

The following discussion of risk factors should be read in conjunction with the financial statements and related notes included under Item 8, Financial Statements and Supplementary Data. Because of these and other factors, past financial performance should not be considered an indication of future performance.

The market price for the trust units may not reflect the value of the net profits interests held by the trust.

The public trading price for the trust units tends to be tied to the recent and expected levels of cash distributions on the trust units. The amounts available for distribution by the trust vary in response to numerous factors outside the control of the trust or XTO Energy, including prevailing prices for oil and natural gas produced from the underlying properties. The market price of the trust units is not necessarily indicative of the value that the trust would realize if the net profits interests were sold to a third party buyer. In addition, such market price is not necessarily reflective of the fact that, since the assets of the trust are depleting assets, a portion of each cash distribution paid on the trust units should be considered by investors as a return of capital, with the remainder being considered as a return on investment. There is no guarantee that distributions made to a unitholder over the life of these depleting assets will equal or exceed the purchase price paid by the unitholder.

Oil and natural gas prices fluctuate due to a number of uncontrollable factors, and any decline will adversely affect the net proceeds payable to the trust and trust distributions.

The trust’s monthly cash distributions are highly dependent upon the prices realized from the sale of natural gas and, to a lesser extent, oil. Oil and natural gas prices can fluctuate widely on a month-to-month basis in response to a variety of factors that are beyond the control of the trust and XTO Energy. Factors that contribute to price fluctuations include instability in oil-producing regions, worldwide economic conditions, weather conditions, the supply and price of domestic and foreign oil, natural gas and natural gas liquids, consumer demand, the price and availability of alternative fuels, the proximity to, and capacity of, transportation facilities and the effect of worldwide energy conservation measures. Moreover, government regulations, such as regulation of natural gas transportation and price controls, can affect product prices in the long term. Lower oil and natural gas prices may reduce the amount of oil and natural gas that is economic to produce and will reduce net profits available to the trust. The volatility of energy prices reduces the predictability of future cash distributions to trust unitholders.

Higher production expense and/or development costs, without concurrent increases in revenue, will directly decrease the net proceeds payable to the trust from the properties underlying the 75% net profits interests.

Production expense and development costs are deducted in the calculation of the trust’s share of net proceeds from properties underlying the 75% net profits interests. Accordingly, higher or lower production expense and development costs, without concurrent changes in revenue, will directly decrease or increase the amount received by the trust for its 75% net profits interests. If development costs and production expense for properties underlying the 75% net profits in a particular state exceed the production proceeds from the properties (as was the case with respect to the properties underlying the Texas working interest for January through April 2009 and the properties underlying the Oklahoma

working interest for February through April 2009), the trust will not receive net proceeds for those properties until future proceeds from production in that state exceed the total of the excess costs plus accrued interest during the deficit period. Development activities may not generate sufficient additional revenue to repay the costs.

Proved reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in reserve estimates or underlying assumptions could cause the quantities and net present value of the reserves to be overstated.

Estimating proved oil and gas reserves is inherently uncertain. Petroleum engineers consider many factors and make assumptions in estimating reserves and future net cash flows. Those factors and assumptions include historical production from the area compared with production rates from similar producing areas, the effects of governmental regulation, assumptions about future commodity prices, production expense and development costs, taxes and capital expenditures, the availability of enhanced recovery techniques and relationships with landowners, working interest partners, pipeline companies and others. Lower oil and gas prices generally cause lower estimates of proved reserves. Ultimately, actual production, revenues and expenditures for the underlying properties will vary from estimates and those variances could be material. Because the trust owns net profits interests, it does not own a specific percentage of the oil and gas reserves. Estimated proved reserves for the net profits interests are based on estimates of reserves for the underlying properties and an allocation method that considers estimated future net proceeds and oil and gas prices. Because trust reserve quantities are determined using an allocation formula, increases or decreases in oil and gas prices can significantly affect estimated reserves of the 75% net profits interests.

Operational risks and hazards associated with the development of the underlying properties may decrease trust distributions.

There are operational risks and hazards associated with the production and transportation of oil and natural gas, including without limitation natural disasters, blowouts, explosions, fires, leakage of oil or natural gas, releases of other hazardous materials, mechanical failures, cratering, and pollution. Any of these or similar occurrences could result in the interruption or cessation of operations, personal injury or loss of life, property damage, damage to productive formations or equipment, damage to the environment or natural resources, or cleanup obligations. The operation of oil and gas properties is also subject to various laws and regulations. Non-compliance with such laws and regulations could subject the operator to additional costs, sanctions or liabilities. The uninsured costs resulting from any of the above or similar occurrences could be deducted as a production expense or development cost in calculating the net proceeds payable to the trust from properties underlying the 75% net profits interests, and would therefore reduce trust distributions by the amount of such uninsured costs.

Cash held by the trustee is not fully insured by the Federal Deposit Insurance Corporation, and future royalty income may be subject to risks relating to the creditworthiness of third parties.

Currently, cash held by the trustee as a reserve for liabilities and for the payment of expenses and distributions to unitholders is invested in Bank of America, N.A. certificates of deposit which are backed by the good faith and credit of Bank of America, N.A., but are only insured by the Federal Deposit Insurance Corporation up to $250,000. Each unitholder should independently assess the creditworthiness of Bank of America, N.A. For more information about the credit rating of Bank of America, N.A., please refer to its periodic filings with the SEC. The trust does not lend money and has limited ability to borrow money, which the trustee believes limits the trust’s risk from the currently tight credit markets. The trust’s future royalty income, however, may be subject to risks relating to the creditworthiness of the operators of the underlying properties and other purchasers of crude oil and natural gas produced from the underlying properties, as well as risks associated with fluctuations in the price of crude oil and natural gas. Information contained in Bank of America, N.A.’s periodic filings with the SEC is not incorporated by reference into this Annual Report on Form 10-K and should not be considered part of this report or any other filing that the trust makes with the SEC.

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

Because XTO Energy does not operate most of the underlying properties, it is unable to significantly influence the operations or future development of the underlying properties. Neither the trustee nor the trust unitholders can influence or control the operation or future development of the underlying properties. The failure of an operator to conduct its

operations or discharge its obligations in a proper manner could have an adverse effect on the net proceeds payable to the trust. Although XTO Energy and the other operators of the underlying properties must adhere to the standard of a prudent operator, they are under no obligation to continue operating the properties. Neither the trustee nor trust unitholders have the right to replace an operator.

The assets of the trust represent interests in depleting assets and, if XTO Energy or any other operators developing the underlying properties do not perform additional successful development projects, the assets may deplete faster than expected. Eventually, the assets of the trust will cease to produce in commercial quantities and the trust will cease to receive proceeds from such assets.

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

Terrorism and continued geopolitical hostilities could adversely affect trust distributions or the market price of the trust units.

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

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

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

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

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

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

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

Trust unitholders have limited voting rights and have limited ability to enforce the trust’s rights against XTO Energy or any other operator of the underlying properties.

The voting rights of a trust unitholder are more limited than those of stockholders of most public corporations. For example, there is no requirement for annual meetings of trust unitholders or for an annual or other periodic re-election of the trustee. Additionally, trust unitholders have no voting rights in XTO Energy or Exxon Mobil Corporation.

The trust indenture and related trust law permit the trustee and the trust to sue XTO Energy or any other operator of the underlying properties to compel them to fulfill the terms of the conveyance of the net profits interests. If the trustee does not take appropriate action to enforce provisions of the conveyance, the recourse of the trust unitholders would likely be limited to bringing a lawsuit against the trustee to compel the trustee to take specified actions. Trust unitholders probably would not be able to sue XTO Energy or any other operator of the underlying properties.

Financial information of the trust is not prepared in accordance with U.S. GAAP.

The financial statements of the trust are prepared on a modified cash basis of accounting, which is a comprehensive basis of accounting other than U.S. generally accepted accounting principles, or U.S. GAAP. Although this basis of accounting is permitted for royalty trusts by the Securities and Exchange Commission, the financial statements of the trust differ from U.S. GAAP financial statements because net profits income is not accrued in the month of production, expenses are not recognized when incurred and cash reserves may be established for certain contingencies that would not be recorded in U.S. GAAP financial statements.

The limited liability of trust unitholders is uncertain.

The trust unitholders are not protected from the liabilities of the trust to the same extent that a shareholder would be protected from a corporation’s liabilities. The structure of the trust does not include the interposition of a limited liability entity such as a corporation or limited partnership which would provide further limited liability protection to trust unitholders. While the trustee is liable for any excess liabilities incurred if the trustee fails to ensure that such liabilities are to be satisfied only out of trust assets, under the laws of Texas, which are unsettled on this point, a unitholder may be jointly and severally liable for any liability of the trust if the satisfaction of such liability was not contractually limited to the assets of the trust and the assets of the trust and the trustee are not adequate to satisfy such liability. As a result, trust unitholders may be exposed to personal liability. The trust, however, is not liable for production costs or other liabilities of the underlying properties.

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

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

•

unexpected drilling conditions;

•

title problems;

•

restricted access to land for drilling or laying pipeline;

•

pressure or irregularities in formations;

•

equipment failures or accidents;

•

adverse weather conditions; and

•

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

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

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

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

Item 1B.

Unresolved Staff Comments

As of December 31, 2011, the trust did not have any unresolved Securities and Exchange Commission staff comments.

Item 2.

Properties

The net profits interests are the principal asset of the trust. The trustee cannot acquire any other asset, with the exception of certain short-term investments as specified under Item 1, Business. The trustee is prohibited from selling any portion of the net profits interests unless approved by at least 80% of the unitholders or at such time as trust gross revenue is less than $1 million for two successive years.

The net profits interests comprise:

the 90% net profits interests which are carved from:

producing royalty and overriding royalty interest properties in Texas, Oklahoma and New Mexico, and

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, 2011 is approximately 12 years. This index is calculated using total proved reserves and estimated 2012 production for the underlying properties. The projected 2012 production is from proved developed producing reserves as of December 31, 2011. Based on estimated future net cash flows at 12-month average oil and gas prices, based on the first-day-of-the-month price for each month in the period, the proved reserves of the underlying properties are approximately 40% oil and 60% natural gas. The underlying properties also include certain nonproducing properties in Texas, Oklahoma and New Mexico that are primarily mineral interests.

Producing Acreage, Wells and Drilling

90% Net Profits Interests Underlying Royalties. Royalty and overriding royalty properties underlying the 90% net profits interests represent 76% of the discounted future net cash flows from trust proved reserves at December 31, 2011. Approximately 77% of the discounted future net cash flows from the 90% net profits interests is from gas reserves, totaling 24.4 Bcf. Oil reserves allocated to the 90% net profits interests are primarily located in West Texas and are estimated to be 505,000 Bbls at December 31, 2011.

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 75% of the trust’s gas sales volumes and 36% of the net profits income for 2011. The trust’s estimated proved gas reserves from this region totaled 19.9 Bcf at December 31, 2011, 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 4,813 gross (approximately 47.2 net) wells, covering almost 60,000 gross acres. Approximately half of these wells are operated by BP America Production Company or ConocoPhillips. Production from conventional gas wells is primarily from the Dakota, Mesaverde and Pictured Cliffs formations.

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

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

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 387,098 gross (approximately 42,494 net) producing acres. Well counts for the underlying royalties cannot be provided because information regarding the number of wells on royalty properties is generally not made available to royalty interest owners.

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

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

Proved reserves from the 75% net profits interests are almost entirely oil, estimated to be approximately 606,000 Bbls at year-end 2011. Proved reserves from these interests represent 24% of the discounted future net cash flows of the trust’s proved reserves at December 31, 2011.

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

The underlying working interest properties consist of 3,813 net producing acres. As of December 31, 2011, there were 1,363 gross (61.9 net) productive oil wells and no wells in process of drilling on these properties. There were eight gross (0.3 net) wells drilled in 2011, and no wells drilled in 2010 or 2009.

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 2011 development costs were $623,384 up 16% from 2010 development costs of $539,048. Development costs were higher in 2011 because of increased development activity related to Texas and Oklahoma properties underlying the 75% net profits interest. January and February 2012 development costs totaled approximately $58,000, primarily incurred in fourth quarter 2011.

As reported to XTO Energy by unit operators in February of each year, budgeted development costs were $907,000 for 2011 and $585,000 for 2010. Actual development costs often differ from amounts budgeted because of changes in product prices and other factors that may affect the timing or selection of projects. 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 $2.4 million for 2012 and $2.3 million for 2013.

Costs exceeded revenues on properties underlying the Texas working interest for January through April 2009 and on properties underlying the Oklahoma working interest for February through April 2009. There were no excess costs at December 31, 2011. For information regarding the effect of excess costs on trust net profits income, see Trustee’s Discussion and Analysis of Financial Condition and Results of Operations, under Item 7.

Estimated Proved Reserves and Future Net Cash Flows

The following are proved reserves of the underlying properties, as estimated by independent engineers, and proved reserves and future net cash flows from proved reserves of the net profits interests, based on an allocation of these reserves, at December 31, 2011:


	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)		Future Net Cash Flows from Proved Reserves (a) (c)
(in thousands)	Oil (Bbls)		Gas (Mcf)		Oil (Bbls)		Gas (Mcf)		Undiscounted		Discounted

90% Net Profits Interests
San Juan Basin		36		22,141		33		19,927	$	115,052	$	53,712
Other New Mexico		42		135		37		132		3,894		1,958
Texas		432		3,238		388		2,915		50,132		25,680
Oklahoma		52		1,722		47		1,468		10,605		5,528

Total		562		27,236		505		24,442		179,683		86,878


75% Net Profits Interests
Texas		714		365		253		129		22,817		12,123
Oklahoma		1,011		139		353		48		28,935		15,513

Total		1,725		504		606		177		51,752		27,636

TOTAL		2,287		27,740		1,111		24,619	$	231,435	$	114,514

(a)

Based on 12-month average oil price of $90.05 per Bbl and $6.24 per Mcf for gas, based on the first-day-of-the-month price for each month in the period. Discounted estimated future net cash flows from proved reserves increased 17% from year-end 2010 to 2011, primarily because of a 23% increase in oil prices and a 15% increase in natural gas prices.

(b)

Since the trust has defined net profits interests, the trust does not own a specific percentage of the oil and gas reserves. Because trust reserve quantities are determined using an allocation formula, any fluctuations in actual or assumed prices or costs will result in revisions to the estimated reserve quantities allocated to the net profits interests.

(c)	Before income taxes since future net cash flows are not subject to taxation at the trust level. Future net cash flows are discounted at an annual rate of 10%.

Proved reserves consist of the following:


	Underlying Properties				Net Profits Interests
	Proved Reserves				Proved Reserves
(in thousands)	Oil (Bbls)		Gas (Mcf)		Oil (Bbls)		Gas (Mcf)

Proved developed reserves		2,287		27,740		1,111		24,619
Proved undeveloped reserves		—		—		—		—

Total proved reserves		2,287		27,740		1,111		24,619

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

The XTO Energy reserve engineering group reviews reserve estimates with our third-party petroleum consultants, Miller and Lents, Ltd., independent petroleum engineers. Miller and Lents, Ltd. estimated oil and gas reserves attributable to the underlying properties as of December 31, 2011, 2010, 2009 and 2008. Miller and Lents’ primary technical person responsible for calculating the trust’s reserves has more than 30 years of experience as a reserve engineer. The estimated reserves for the underlying properties are then used by XTO Energy to calculate the estimated oil and gas reserves attributable to the net profits interests. Numerous uncertainties are inherent in estimating reserve volumes and values, and such estimates are subject to change as additional information becomes available. The reserves actually recovered and the timing of production of these reserves may be substantially different from the original estimates.

Reserve quantities and revenues for the net profits interests were estimated from projections of reserves and revenues attributable to the combined interests of the trust and XTO Energy in the subject properties. Since the trust has defined net profits interests, the trust does not own a specific percentage of the oil and gas reserve quantities. Accordingly, reserves allocated to the trust pertaining to its 75% net profits interests in the working interest properties have effectively been reduced to reflect recovery of the trust’s 75% portion of applicable production and development costs. Because trust reserve quantities are determined using an allocation formula, any fluctuations in actual or assumed prices or costs will result in revisions to the estimated reserve quantities allocated to the net profits interests.

Oil and Natural Gas Production

Trust production is recognized in the period net profits income is received, which is the month following receipt by XTO Energy, and generally two months after the time of oil production and three months after gas production. Oil and gas production and average sales prices attributable to the underlying properties and the net profits interests for each of the three years ended December 31 were as follows:


	90% Net Profits Interests						75% Net Profits Interests						Total
	2011		2010		2009		2011		2010		2009		2011		2010		2009
Production

Underlying Properties

Oil—Sales (Bbls)		67,651		61,282		68,326		128,444		135,820		151,154		196,095		197,102		219,480
Average per day (Bbls)		185		168		187		352		372		414		537		540		601
Gas—Sales (Mcf)		1,840,374		2,054,352		1,975,850		31,280		43,612		50,758		1,871,654		2,097,964		2,026,608
Average per day (Mcf)		5,042		5,628		5,413		86		120		139		5,128		5,748		5,552

Net Profits Interests

Oil—Sales (Bbls)		56,922		51,014		58,833		49,474		48,614		17,005		106,396		99,628		75,838
Average per day (Bbls)		156		140		161		135		133		47		291		273		208
Gas—Sales (Mcf)		1,631,963		1,821,708		1,761,108		11,656		15,181		7,370		1,643,619		1,836,889		1,768,478
Average per day (Mcf)		4,471		4,991		4,825		32		42		20		4,503		5,033		4,845

Average Sales Price

Oil (per Bbl)		$87.40		$73.52		$54.94		$86.52		$71.03		$48.96		$86.82		$71.80		$50.82
Gas (per Mcf)		$7.36		$7.11		$5.64		$7.84		$4.66		$3.26		$7.37		$7.06		$5.58

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	2011		2010		2009
New Mexico royalty interest		1,368,989		1,608,164		1,429,350
Oklahoma royalty interest		212,711		186,526		261,355
Texas royalty interest		258,674		259,662		285,146
Texas working interest		19,248		31,109		31,591
Oklahoma working interest		12,032		12,503		19,166

Total		1,871,654		2,097,964		2,026,608


	Underlying Oil Production (Bbls)
Conveyance	2011		2010		2009
New Mexico royalty interest		7,188		7,669		8,393
Oklahoma royalty interest		7,807		6,466		7,185
Texas royalty interest		52,656		47,147		52,748
Texas working interest		56,164		60,639		67,088
Oklahoma working interest		72,280		75,181		84,066

Total		196,095		197,102		219,480

Nonproducing Acreage

The underlying nonproducing royalties contain approximately 240,000 gross (approximately 30,000 net) acres in Texas, Oklahoma and New Mexico which were nonproducing at the date of the trust’s creation. The trust is entitled to 10% of oil and gas production attributable to the underlying mineral interests, but is not entitled to delay rental payments or lease bonuses. There has been no significant development of such nonproducing acreage since the trust’s creation.

Pricing and Sales Information

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

Regulation

Natural Gas Regulation

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

Federal Regulation of Oil

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

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

Environmental Regulation

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

There is an increased focus by local, national and international regulatory bodies on greenhouse gas (GHG) emissions and climate change. Several states have adopted climate change legislation and regulations, and various other regulatory bodies have announced their intent to regulate GHG emissions or adopt climate change regulations. As these regulations are under development, XTO Energy is unable to predict the total impact of the potential regulations upon the operators of the underlying properties, and it is possible that the operators of the underlying properties could face increases in operating costs in order to comply with climate change or GHG emissions legislation, which costs could reduce net proceeds payable to the trust and trust distributions.

State Regulation

The various states regulate the production and sale of oil and natural gas, including imposing requirements for obtaining drilling permits, the method of developing new fields, the spacing and operation of wells and the prevention of waste of oil and gas resources. The rates of production may be regulated and the maximum daily production allowables from both oil and gas wells may be established on a market demand or conservation basis, or both.

Federal Income Taxes

For federal income tax purposes, the trust constitutes a fixed investment trust which 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 2011, the trust 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 if the adjusted basis of such property includes adjustments for deductions for depletion under Section 611 of the Internal Revenue 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.

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. U.S. Trust, Bank of America Private Wealth Management, EIN: 56-0906609, Post Office Box 830650, Dallas, Texas. 75283-0650, telephone number 1-877-228-5084, email address trustee@crosstimberstrust.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.crosstimberstrust.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 either 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 1% on gross revenues less certain deductions, as specifically set forth in the Texas franchise tax statutes. Entities subject to tax generally include trusts unless otherwise exempt and most other types of entities that provide limited liability protection. 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 exempt from Texas franchise tax as a “passive entity.” Because the trust has been 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 has been required to include its Texas portion of trust revenues in its own Texas franchise tax computation. This revenue has been 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.

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 2011 and 2010:

Sales Price

Distributions

per Unit

Quarter

High

Low

2011

First

48.50

40.12

0.704029

Second

47.89

38.72

0.738355

Third

48.45

37.83

0.860987

Fourth

51.00

40.00

0.689378

2.992749


2010
First	$	35.00	$	28.21	$	0.683096
Second		39.48		31.00		0.747234
Third		36.92		33.11		0.677215
Fourth		42.26		35.14		0.680009

					$	2.787554

At December 31, 2011, there were 6,000,000 units outstanding and approximately 313 unitholders of record; 5,816,251 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
	2011		2010		2009		2008		2007
Net Profits Income	$	18,381,657	$	17,142,087	$	11,742,545	$	31,311,215	$	20,189,267
Distributable Income		17,956,494		16,725,324		11,316,138		30,942,420		19,805,724
Distributable Income per Unit		2.992749		2.787554		1.886023		5.157070		3.300954
Distributions per Unit		2.992749		2.787554		1.886023		5.157070		3.300954
Total Assets at Year-End		14,629,000		15,935,049		17,256,102		18,771,025		20,147,900

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)
	2011		2010		2009		2011		2010
Sales Volumes
Oil (Bbls) (b)
Underlying properties		196,095		197,102		219,480		45,803		48,399
Average per day		537		540		601		498		526
Net profits interests		106,396		99,628		75,838		21,397		24,450
Gas (Mcf) (b)
Underlying properties		1,871,654		2,097,964		2,026,608		484,569		549,311
Average per day		5,128		5,748		5,552		5,267		5,971
Net profits interests		1,643,619		1,836,889		1,768,478		419,258		473,707

Average Sales Price
Oil (per Bbl)		$86.82		$71.80		$50.82		$82.07		$72.40
Gas (per Mcf)		$7.37		$7.06		$5.58		$7.65		$6.57

Revenues
Oil sales		$17,025,533		$14,152,470		$11,154,802		$3,759,153		$3,503,971
Gas sales		13,785,133		14,813,040		11,315,933		3,704,979		3,611,390

Total Revenues		30,810,666		28,965,510		22,470,735		7,464,132		7,115,361


Costs
Taxes, transportation and other		4,259,521		4,136,302		3,495,414		1,096,844		959,866
Production expense (c)		4,580,205		4,502,466		5,092,484		1,323,728		1,114,907
Development costs		623,384		539,048		601,502		211,174		230,014
Excess costs (d)		—		—		6,995		—		—

Total Costs		9,463,110		9,177,816		9,196,395		2,631,746		2,304,787

Net Proceeds		$21,347,556		$19,787,694		$13,274,340		$4,832,386		$4,810,574

Net Profits Income		$18,381,657		$17,142,087		$11,742,545		$4,204,181		$4,130,924

(a)

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

(b)

Oil and gas sales volumes are allocated to the net profits interests based upon a formula that considers oil and gas prices and the total amount of production expense and development costs. As product prices change, the trust’s share of the production volumes is impacted as the quantity of production to cover expenses in reaching the net profits break-even level changes inversely with price. As such, the underlying property production volume changes may not correlate with the trust’s net profit share of those volumes in any given period. Therefore, comparative discussion of oil and gas sales volumes is based on the underlying properties.

(c)

Production expense is primarily from seven working interest properties in the 75% net profits interest. Five of these properties are not operated by XTO Energy or ExxonMobil. Production expense includes an overhead charge which is deducted and retained by the operator. As of December 31, 2011, this charge was $34,202 per month (including a monthly overhead charge of $2,656 which XTO Energy deducts as operator of the Penwell Unit and $4,507 which ExxonMobil 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 8 to Financial Statements under Item 8, Financial Statements and Supplementary Data.

Results of Operations

Years Ended December 31, 2011, 2010 and 2009

Net profits income for 2011 was $18,381,657 as compared with $17,142,087 for 2010 and $11,742,545 for 2009. The 7% increase in net profits income from 2010 to 2011 was primarily because of increased oil and gas prices ($2.9 million), partially offset by decreased gas production ($1.5 million). The 46% increase in net profits income from 2009 to 2010 was primarily because of increased oil and gas prices ($6.3 million), increased gas production ($0.5 million) and decreased production expense ($0.4 million), partially offset by decreased oil production ($1.3 million) and higher taxes, transportation and other costs ($0.6 million). During 2011, 2010 and 2009, 52%, 60% and 65%, respectively, of net profits income was derived from gas sales.

Trust administration expense was $425,539 in 2011 as compared to $417,063 in 2010 and $426,630 in 2009. Interest income was $376 in 2011, $300 in 2010 and $223 in 2009. 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 1% from 2010 to 2011 compared to a 10% decrease from 2009 to 2010. Oil sales volumes in 2011 decreased from 2010 primarily because of natural production decline, partially offset by increased production from new wells and workovers and the timing of cash receipts. Oil sales volumes in 2010 decreased from 2009 primarily because of natural production decline and the timing of cash receipts.

Gas. Underlying gas sales volumes decreased 11% from 2010 to 2011 compared to a 4% increase from 2009 to 2010. Gas sales volumes in 2011 decreased from 2010 primarily because of the timing of cash receipts and natural production decline, partially offset by increased production from new wells and workovers. Gas sales volumes in 2010 increased from 2009 primarily because of the timing of cash receipts and increased production from new wells and workovers, partially offset by natural production decline.

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 2011 was $86.82 per Bbl, 21% higher than the 2010 average oil price of $71.80, which was 41% higher than the 2009 average price of $50.82. Oil prices are expected to remain volatile. The average NYMEX price for November 2011 through January 2012 was $98.53 per Bbl. At February 10, 2012, the average NYMEX oil price for the following 12 months was $100.99 per Bbl.

Gas. The 2011 average gas price was $7.37 per Mcf, a 4% increase from the 2010 average gas price of $7.06, which was 27% higher than the 2009 average price of $5.58. Natural gas prices are affected by the level of North American production, weather, crude oil and natural gas liquids prices, the U.S. economy, storage levels and import levels of liquefied natural gas. Natural gas prices are expected to remain volatile. The average NYMEX price for fourth quarter 2011 was $3.55 per MMBtu. At February 10, 2012, the average NYMEX gas price for the following 12 months was $3.08 per MMBtu.

Costs

Because properties underlying the 90% net profits interests are royalty and overriding royalty interests, the calculation of net profits income from these interests only includes deductions for production and property taxes, legal costs, and marketing and transportation charges. In addition to these costs, the calculation of net profits income from the 75% net profits interests includes deductions for production expense and development costs since the related underlying properties are working interests. Net profits income is calculated monthly for each of the five conveyances under which the net profits interests were conveyed to the trust. If monthly costs exceed revenues for any conveyance, such excess costs must be recovered, with accrued interest, from future net proceeds of that conveyance and cannot reduce net profits income from other conveyances. Costs have never exceeded revenues from 90% net profits interests, nor are they expected to in the future. Significantly lower oil prices and elevated costs caused costs to exceed revenues by a total of $229,340 ($172,005 net to the trust) on properties underlying the Texas working interest for January through April 2009 and by $319,745 ($239,809 net to the trust) on properties underlying the Oklahoma working interest for February through April 2009. However, these excess costs did not reduce net proceeds from the remaining conveyances. XTO Energy advised the trustee that increased oil prices and decreased costs led to the full recovery of excess costs, plus accrued interest, during 2009. Interest paid on these excess costs totaled $6,995 ($5,246 net to the trust) in 2009. There were no excess costs at December 31, 2011.

Total costs deducted in the calculation of net profits income were $9.5 million in 2011, $9.2 million in 2010 and $9.2 million in 2009. The 3% increase in costs from 2010 to 2011 is attributable to increased property taxes related to the timing of cash disbursements, increased oil production taxes related to higher oil revenues and increased development costs, partially offset by decreased gas production taxes and other deductions related to lower gas revenues. Total costs remained relatively flat from 2009 to 2010 as increased taxes, transportation and other costs due to higher oil and gas revenues were offset by decreased production expense related to decreased repairs and maintenance, overhead on nonopertated properties and 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 $2.4 million for 2012 and $2.3 million for 2013, as compared to budgeted development costs of $907,000 and actual development costs of $623,000 for 2011. 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.

Fourth Quarter 2011 and 2010

During the quarter ended December 31, 2011, the trust received net profits income totaling $4,204,181, compared with fourth quarter 2010 net profits income of $4,130,924. This 2% increase is primarily attributable to increased oil and gas prices ($0.9 million), partially offset by decreased oil and gas production ($0.6 million) and increased production expense ($0.2 million).

Administration expense was $68,015 and trust interest income was $102, resulting in fourth quarter 2011 distributable income of $4,136,268, or $0.689378 per unit. Distributable income for fourth quarter 2010 was $4,080,054, or $0.680009 per unit. Distributions to unitholders for the quarter ended December 31, 2011 were:


Record Date	Payment Date	Per Unit
October 31, 2011	November 15, 2011	$	0.236736
November 30, 2011	December 14, 2011		0.250432
December 30, 2011	January 17, 2012		0.202210

		$	0.689378

Volumes

Fourth quarter 2011 underlying oil sales volumes were 45,803 Bbls, or 5% lower than 2010 levels and underlying gas sales volumes were 484,569 Mcf, or 12% lower than 2010 levels. Oil and gas sales volumes decreased in 2011 primarily because of natural production decline and the timing of cash receipts.

Prices

The average fourth quarter 2011 oil price was $82.07 per Bbl, 13% higher than the fourth quarter 2010 average price of $72.40. The average fourth quarter 2011 gas price was $7.65 per Mcf, 16% higher than the fourth quarter 2010 average price of $6.57. For further information about oil and gas prices, see “Years Ended December 31, 2011, 2010 and 2009 – Prices” above.

Costs

Costs deducted in the calculation of fourth quarter 2011 net profits income increased $326,959, or 14%, from fourth quarter 2010. This increase was primarily related to increased production expense due to increased power and fuel, repairs and maintenance and outside operated costs, partially offset by decreased labor costs and increased taxes, transportation and other costs due to increased property taxes related to the timing of cash disbursements.

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

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, 2011, other than the December distribution payable to unitholders in January 2012, 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	$	1,213,260	$	1,213,260	$	—	$	—	$	—

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, 2011, this monthly charge was $34,202 ($25,652 net to the trust). Included in this monthly overhead charge is a charge XTO Energy deducts as operator of the Penwell Unit and ExxonMobil deducts as operator of the Hewitt Unit. As of December 31, 2011, monthly overhead attributable to the Penwell Unit was $2,656 ($1,992 net to the trust) and monthly overhead attributable to the Hewitt Unit was $4,507 ($3,380 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 6 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.

Oil and Gas Reserves

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

The standardized measure of discounted future net cash flows and changes in such cash flows, as reported in Note 9 to Financial Statements under Item 8, Financial Statements and Supplementary Data, is prepared using assumptions required by the Financial Accounting Standards Board and the Securities and Exchange Commission. Such assumptions include using 12-month average oil and gas prices, based on the first-day-of-the-month price for each month in the period for 2011, 2010 and 2009, and year end costs for estimated future development and production expenditures. Prior to 2009, standardized measure was calculated using year end oil and gas prices and costs. Discounted future net cash flows are calculated using a 10% rate. Changes in any of these assumptions, including consideration of other factors, could have a significant impact on the standardized measure. Accordingly, the standardized measure does not represent XTO Energy’s or the trustee’s estimated current market value of proved reserves.

Forward-Looking Statements

Certain information included in this annual report and other materials filed, or to be filed, by the trust with the Securities and Exchange Commission (as well as information included in oral statements or other written statements made or to be made by XTO Energy or the trustee) contain forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended, and Section 27A of the Securities Act of 1933, as amended, relating to the trust, operations of the underlying properties and the oil and gas industry. Such forward-looking statements may concern, among other things, development activities, future development plans, increased density drilling, reserve-to-production ratios, future net cash flows, maintenance projects, development, production and other costs, oil and gas prices, pricing differentials, proved reserves, production levels, litigation, regulatory matters and competition. Such forward-looking statements are based on XTO Energy’s current plans, expectations, assumptions, projections and estimates and are identified by words such as “expects,” “intends,” “plans,” “projects,” “anticipates,” “predicts,” “believes,” “goals,” “estimates,” “should,” “could,” and similar words that convey the uncertainty of future events. These statements are not guarantees of future performance and involve certain risks, uncertainties and assumptions that are difficult to predict. Therefore, actual results may differ materially from expectations, estimates or assumptions expressed in, implied in, or forecasted in such forward-looking statements. Some of the risk factors that could cause actual results to differ materially are explained in Item 1A, Risk Factors.

Item 7A.

Quantitative and Qualitative Disclosures about Market Risk

The only assets of and sources of income to the trust are the net profits interests, which generally entitle the trust to receive a share of the net profits from oil and gas production from the underlying properties. Consequently, the trust is exposed to market risk from fluctuations in oil and gas prices. The trust is a passive entity and, other than the trust’s ability to periodically borrow money as necessary to pay expenses, liabilities and obligations of the trust that cannot be paid out of cash held by the trust, the trust is prohibited from engaging in borrowing transactions. The amount of any such borrowings is unlikely to be material to the trust. In addition, the trustee is prohibited by the trust indenture from engaging in any business activity or causing the trust to enter into any investments other than investing cash on hand in specific short-term cash investments. Therefore, the trust cannot hold any derivative financial instruments. As a result of the limited nature of its borrowing and investing activities, the trust is not subject to any material interest rate market risk. Additionally, any gains or losses from any hedging activities conducted by XTO Energy are specifically excluded from the calculation of net proceeds due the trust under the forms of the conveyances. The trust does not engage in transactions in foreign currencies which could expose the trust to any foreign currency related market risk.

Item 8.

Financial Statements and Supplementary Data


	Page
Statements of Assets, Liabilities and Trust Corpus		26
Statements of Distributable Income		27
Statements of Changes in Trust Corpus		28
Notes to Financial Statements		29
Reports of Independent Registered Public Accounting Firm		37

All financial statement schedules are omitted as they are inapplicable or the required information has been included in the consolidated financial statements or notes thereto.

CROSS TIMBERS ROYALTY TRUST

Statements of Assets, Liabilities and Trust Corpus


	December 31
	2011		2010
Assets
Cash and short-term investments	$	1,213,231	$	1,413,665
Interest to be received		29		37
Net profits interests in oil and gas properties—net (Notes 1 and 2)		13,415,740		14,521,347

		$14,629,000	$	15,935,049


Liabilities and Trust Corpus
Distribution payable to unitholders	$	1,213,260	$	1,413,702
Trust corpus (6,000,000 units of beneficial interest authorized and outstanding)		13,415,740		14,521,347

	$	14,629,000	$	15,935,049

See accompanying notes to financial statements.

CROSS TIMBERS ROYALTY TRUST

Statements of Distributable Income


	Year Ended December 31
	2011		2010		2009
Net profits income	$	18,381,657	$	17,142,087	$	11,742,545
Interest income		376		300		223

Total income		18,382,033		17,142,387		11,742,768
Administration expense		425,539		417,063		426,630

Distributable income	$	17,956,494	$	16,725,324	$	11,316,138

Distributable income per unit (6,000,000 units)	$	2.992749	$	2.787554	$	1.886023

See accompanying notes to financial statements.

CROSS TIMBERS ROYALTY TRUST

Statements of Changes in Trust Corpus


	Year Ended December 31
	2011			2010			2009
Trust corpus, beginning of year	$	14,521,347		$	16,188,498		$	17,255,761
Amortization of net profits interests		(1,105,607	)		(1,667,151	)		(1,067,263	)
Distributable income		17,956,494			16,725,324			11,316,138
Distributions declared		(17,956,494	)		(16,725,324	)		(11,316,138	)

Trust corpus, end of year	$	13,415,740		$	14,521,347		$	16,188,498

See accompanying notes to financial statements.

CROSS TIMBERS ROYALTY TRUST

NOTES TO FINANCIAL STATEMENTS

1. Trust Organization and Provisions

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

—

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

—

75% net profits interests in certain working interest properties in Texas and Oklahoma.

The underlying properties from which the net profits interests were carved are currently owned by XTO Energy (Note 6). The trust’s initial public offering was in February 1992.

Bank of America, N.A. is the trustee of the trust. In 2007 the Bank of America private wealth management group officially became known as “U.S. Trust, Bank of America Private Wealth Management.” The legal entity that serves as the trustee of the trust did not change, and references in this Annual Report to U.S. Trust, Bank of America Private Wealth Management shall describe the legal entity Bank of America, N.A. The trust indenture provides, among other provisions, that:

—

the trust may not engage in any business activity or acquire any assets other than the net profits interests and specific short-term cash investments;

—

the trust may not dispose of all or part of the net profits interests unless approved by 80% of the unitholders, or upon trust termination, and any sale must be for cash with the proceeds promptly distributed to the unitholders;

—

the trustee may establish a cash reserve for payment of any liability that is contingent or not currently payable;

—

the trustee may borrow funds required to pay trust liabilities if fully repaid prior to further distributions to unitholders;

—

the trustee will make monthly cash distributions to unitholders (Note 3); and

—

the trust will terminate upon the first occurrence of:

—

disposition of all net profits interests pursuant to terms of the trust indenture,

—

gross revenue of the trust is less than $1 million per year for two successive years, or

—

a vote of 80% of the unitholders to terminate the trust in accordance with provisions of the trust indenture.

2. Basis of Accounting

The financial statements of the trust are prepared on the following basis and are not intended to present financial position and results of operations in conformity with U.S. generally accepted accounting principles:

—

Net profits income is recorded in the month received by the trustee (Note 3).

—

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

—

Trust expenses are recorded based on liabilities paid and cash reserves established by the trustee for liabilities and contingencies.

—

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

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

—

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

—

Expenses are recognized when paid rather than when incurred.

—

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

This comprehensive basis of accounting corresponds to the accounting permitted for royalty trusts by the U.S. Securities and Exchange Commission, as specified by Staff Accounting Bulletin Topic 12:E, Financial Statements of Royalty Trusts.

Most accounting pronouncements apply to entities whose financial statements are prepared in accordance with U.S. generally accepted accounting principles, directing such entities to accrue or defer revenues and expenses in a period other than when such revenues were received or expenses were paid. Because the trust’s financial statements are prepared on the modified cash basis, as described above, most accounting pronouncements are not applicable to the trust’s financial statements.

The initial carrying value of the net profits interests of $61,100,449 was XTO Energy’s historical net book value of the interests on February 12, 1991, the date of the transfer to the trust. Amortization of the net profits interests is calculated on a unit-of-production basis and charged directly to trust corpus. Accumulated amortization was $47,684,709 as of December 31, 2011 and $46,579,102 as of December 31, 2010.

3. Distributions to Unitholders

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

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

XTO Energy, as owner of the underlying properties, computes net profits income separately for each of the five conveyances. If costs exceed gross proceeds for any conveyance, such excess costs must be recovered, with accrued interest, from future net proceeds of that conveyance and cannot reduce net profits income from the other conveyances (Note 8).

4. Federal Income Taxes

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

5. State Taxes

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.

6. XTO Energy Inc.

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

In computing net profits income for the 75% net profits interests (Note 3), XTO Energy deducts an overhead charge as reimbursement for costs associated with monitoring these interests. This charge at December 31, 2011 was $34,202 per month, or $410,424 annually (net to the trust of $307,818 annually). Included in this monthly overhead charge is a charge XTO Energy deducts as operator of the Penwell Unit and ExxonMobil deducts as operator of the Hewitt Unit. As of December 31, 2011, overhead attributable to the Penwell Unit was $2,656 per month, or $31,872 annually (net to the trust of $23,904 annually) and overhead attributable to the Hewitt Unit was $4,507 per month, or $54,084 annually (net to the trust of $40,563 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.

7. Contingencies

8. Excess Costs

Significantly lower oil prices and elevated costs caused costs to exceed revenues by a total of $229,340 ($172,005 net to the trust) on properties underlying the Texas working interest for January through April 2009 and by $319,745 ($239,809 net to the trust) on properties underlying the Oklahoma working interest for February through April 2009. However, these costs did not reduce net proceeds from the remaining conveyances. XTO Energy advised the trustee that increased oil prices and decreased costs led to the full recovery of excess costs, plus accrued interest, during 2009. Interest paid on these excess costs totaled $6,995 ($5,246 net to the trust) in 2009. There were no excess costs in 2010 or 2011.

9. Supplemental Oil and Gas Reserve Information (Unaudited)

Oil and Natural Gas Reserves

Proved oil and gas reserves have been estimated by independent petroleum engineers. Proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs and under existing economic conditions, operating methods, and government regulation before the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain. Proved developed reserves are the quantities expected to be recovered through existing wells with existing equipment and operating methods in which the cost of the required

equipment is relatively minor compared with the cost of a new well. Due to the inherent uncertainties and the limited nature of reservoir data, such estimates are subject to change as additional information becomes available. The reserves actually recovered and the timing of production of these reserves may be substantially different from the original estimate. Revisions result primarily from new information obtained from development drilling and production history and from changes in economic factors.

Standardized Measure

The standardized measure of discounted future net cash flows and changes in such cash flows are prepared using assumptions required by the Financial Accounting Standards Board. Such assumptions include the use of 12-month average prices for oil and gas, based on the first-day-of-the-month price for each month in the period for 2011, 2010 and 2009, and year end costs for estimated future development and production expenditures to produce the proved reserves. Prior to 2009, standardized measure was calculated using year end oil and gas prices and costs. Future net cash flows are discounted at an annual rate of 10%. No provision is included for federal income taxes since future net cash flows are not subject to taxation at the trust level.

The standardized measure does not represent management’s estimate of our future cash flows or the value of proved oil and gas reserves. Probable and possible reserves, which may become proved in the future, are excluded from the calculations. Furthermore, prices used to determine the standardized measure are influenced by supply and demand as affected by recent economic conditions as well as other factors and may not be the most representative in estimating future revenues or reserve data.

Estimated costs to plug and abandon wells on the underlying working interest properties at the end of their productive lives have not been deducted from cash flows since this is not a legal obligation of the trust. These costs are the legal obligation of XTO Energy as the owner of the underlying working interests and will only be deducted from net proceeds payable to the trust if net proceeds from the related conveyance exceed such costs when paid, subject to excess cost carryforward provisions (Note 3).

Oil prices used to determine the standardized measure were based on average realized oil prices of $90.05 per Bbl in 2011, $73.20 per Bbl in 2010, and $53.92 per Bbl in 2009 and a year end realized oil price of $36.46 per Bbl in 2008. The weighted average realized gas prices used to determine the standardized measure were $6.24 per Mcf in 2011, $5.42 per Mcf in 2010, and $4.07 per Mcf in 2009 and a year end realized gas price of $4.27 per Mcf in 2008. In 2011, 2010 and 2009, we used average oil and gas prices, based on the first-day-of-the-month price for each month in the period. For periods prior to 2009, we used year end oil and gas prices.

Proved Reserves


	Net Profits Interests
	90% Net Profits Interests						75% Net Profits Interests						Total						Underlying Properties
(in thousands)	Oil (Bbls)			Gas (Mcf)			Oil (Bbls)			Gas (Mcf)			Oil (Bbls)			Gas (Mcf)			Oil (Bbls)			Gas (Mcf)

Balance, December 31, 2008		532			25,463			317			95			849			25,558			2,119			28,836
Extensions, additions and discoveries		9			1,240			—			—			9			1,240			10			1,379
Revisions of prior estimates		21			639			53			9			74			648			282			777
Production		(59	)		(1,761	)		(17	)		(7	)		(76	)		(1,768	)		(219	)		(2,027	)

Balance, December 31, 2009		503			25,581			353			97			856			25,678			2,192			28,965
Extensions, additions and discoveries		5			594			—			—			5			594			6			659
Revisions of prior estimates		46			413			257			69			303			482			303			546
Production		(51	)		(1,822	)		(49	)		(15	)		(100	)		(1,837	)		(197	)		(2,098	)

Balance, December 31, 2010		503			24,766			561			151			1,064			24,917			2,304			28,072

Extensions, additions and discoveries		7			324			—			—			7			324			8			360
Revisions of prior estimates		52			984			94			38			146			1,022			171			1,180
Production		(57	)		(1,632	)		(49	)		(12	)		(106	)		(1,644	)		(196	)		(1,872	)

Balance, December 31, 2011		505			24,442			606			177			1,111			24,619			2,287			27,740

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

Proved Developed Reserves


	Net Profits Interests
	90% Net Profits Interests				75% Net Profits Interests				Total				Underlying Properties
(in thousands)	Oil (Bbls)		Gas (Mcf)		Oil (Bbls)		Gas (Mcf)		Oil (Bbls)		Gas (Mcf)		Oil (Bbls)		Gas (Mcf)
December 31, 2008		532		25,463		316		93		848		25,556		2,114		28,825

December 31, 2009		503		25,581		353		97		856		25,678		2,192		28,965

December 31, 2010		503		24,766		561		151		1,064		24,917		2,304		28,072

December 31, 2011		505		24,442		606		177		1,111		24,619		2,287		27,740

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)	2011			2010			2009			2011			2010			2009			2011			2010			2009
*Net Profits Interests*
Future cash inflows	$	197,287		$	172,407		$	133,186		$	55,876		$	41,539		$	19,266		$	253,163		$	213,946		$	152,452
Future production taxes		(17,604	)		(13,562	)		(10,722	)		(4,124	)		(2,590	)		(1,179	)		(21,728	)		(16,152	)		(11,901	)

Future net cash flows		179,683			158,845			122,464			51,752			38,949			18,087			231,435			197,794			140,551
10% discount factor		(92,805	)		(81,698	)		(62,521	)		(24,116	)		(17,973	)		(7,004	)		(116,921	)		(99,671	)		(69,525	)

Standardized measure	$	86,878		$	77,147		$	59,943		$	27,636		$	20,976		$	11,083		$	114,514		$	98,123		$	71,026


*Underlying Properties*
Future cash inflows																			$	378,980		$	320,767		$	236,719
Future production costs																				(110,330	)		(92,341	)		(76,532	)

Future net cash flows																				268,650			228,426			160,187
10% discount factor																				(135,271	)		(114,739	)		(78,807	)

Standardized measure																			$	133,379		$	113,687		$	81,380

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


	90% Net									75% Net
	Profits Interests									Profits Interests									Total
(in thousands)	2011			2010			2009			2011			2010			2009			2011			2010			2009
*Net Profits Interests*
Standardized measure, January 1	$	77,147		$	59,943		$	57,611		$	20,976		$	11,083		$	6,862		$	98,123		$	71,026		$	64,473
Extensions, additions and discoveries		1,210			1,866			2,669			—			—			—			1,210			1,866			2,669
Accretion of discount		6,506			5,063			4,859			1,830			994			625			8,336			6,057			5,484
Revisions of prior estimates, changes in price and other		16,241			24,083			5,524			8,986			12,233			4,618			25,227			36,316			10,142
Net profits income		(14,226	)		(13,808	)		(10,720	)		(4,156	)		(3,334	)		(1,022	)		(18,382	)		(17,142	)		(11,742	)

Standardized measure, December 31	$	86,878		$	77,147		$	59,943		$	27,636		$	20,976		$	11,083		$	114,514		$	98,123		$	71,026

*Underlying Properties*
Standardized measure, January 1																			$	113,687		$	81,380		$	73,162

Revisions:
Prices and costs																				24,845			42,425			9,180
Quantity estimates																				5,807			1,196			3,678
Accretion of discount																				9,669			6,951			6,232
Future development costs																				(623	)		(539	)		(587	)
Other																				(2	)		(12	)		(3	)

Net revisions																				39,696			50,021			18,500
Extensions, additions and discoveries																				1,344			2,074			2,999
Production																				(21,971	)		(20,327	)		(13,883	)
Development costs																				623			539			602

Net change																				19,692			32,307			8,218

Standardized measure, December 31																			$	133,379		$	113,687		$	81,380

11. Quarterly Financial Data (Unaudited)

The following is a summary of net profits income, distributable income and distributable income per unit by quarter for 2011 and 2010:


	Net Profits Income		Distributable Income		Distributable Income per Unit

2011

First Quarter	$	4,350,853	$	4,224,174	$	0.704029
Second Quarter		4,569,004		4,430,130		0.738355
Third Quarter		5,257,619		5,165,922		0.860987
Fourth Quarter		4,204,181		4,136,268		0.689378

	$	18,381,657	$	17,956,494	$	2.992749


2010

First Quarter	$	4,269,080	$	4,098,576	$	0.683096
Second Quarter		4,599,294		4,483,404		0.747234
Third Quarter		4,142,789		4,063,290		0.677215
Fourth Quarter		4,130,924		4,080,054		0.680009

	$	17,142,087	$	16,725,324	$	2.787554

Report of Independent Registered Public Accounting Firm

To the Unitholders of Cross Timbers Royalty Trust and

Bank of America, N.A., Trustee

We have audited the accompanying statement of assets, liabilities and trust corpus of Cross Timbers Royalty Trust (the “Trust”) as of December 31, 2011, and the related statements of distributable income and changes in trust corpus for the year then ended. We also have audited the Trust’s internal control over financial reporting as of December 31, 2011, based on criteria established in Internal Control—Integrated Framework 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 audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit 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 audit 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 audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides 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, 2011, and the distributable income and changes in trust corpus for the year then ended, 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, 2011, based on criteria established in Internal Control—Integrated Framework issued by COSO.

/s/ PricewaterhouseCoopers LLP

Dallas, Texas

February 29, 2012

Report of Independent Registered Public Accounting Firm

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

We have audited the accompanying statement of assets, liabilities, and trust corpus of the Cross Timbers Royalty Trust as of December 31, 2010 and related statements of distributable income and changes in trust corpus for each of the years in the two-year period ended December 31, 2010. The trustee of Cross Timbers Royalty Trust is responsible for these financial statements. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by the trustee, and evaluating the overall financial statement presentation. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

As described in note 2 to the financial statements, these financial statements were prepared on the modified cash basis of accounting, which is a comprehensive basis of accounting other than accounting principles generally accepted in the United States of America.

In our opinion, the financial statements referred to above present fairly, in all material respects, the assets, liabilities, and trust corpus of Cross Timbers Royalty Trust as of December 31, 2010, and its distributable income and changes in trust corpus for each of the years in the two-year period ended December 31, 2010, in conformity with the modified cash basis of accounting described in note 2.

KPMG LLP

Fort Worth, Texas

February 24, 2011

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, Bank of America, N.A., also known as U.S. Trust, Bank of America Private Wealth Management, is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Rule 13a-15(f) promulgated under the Securities Exchange Act of 1934, as amended. The trustee conducted an evaluation of the effectiveness of the trust’s internal control over financial reporting based on the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on the trustee’s evaluation under the framework in Internal Control — Integrated Framework, the trustee concluded that the trust’s internal control over financial reporting was effective as of December 31, 2011. The effectiveness of the trust’s internal control over financial reporting as of December 31, 2011 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, 2011 that have materially affected, or are reasonably likely to materially affect, the trust’s internal control over financial reporting.

Item 9B. Other Information

None.

PART III

Item 10.

Directors, Executive Officers and Corporate Governance

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

Section 16(a) of the Securities Exchange Act of 1934 requires that directors, officers, and beneficial owners of more than 10% of the registrant’s equity securities file initial reports of beneficial ownership and reports of changes in beneficial ownership with the Securities and Exchange Commission and the New York Stock Exchange. To the trustee’s knowledge, based solely on the information furnished to the trustee, the trustee is unaware of any person that failed to file on a timely basis reports required by Section 16(a) filing requirements with respect to the trust units of beneficial interest during and for the year ended December 31, 2011.

Because the trust has no employees, it does not have a code of ethics. Employees of the trustee, U.S. Trust, Bank of America Private Wealth Management, must comply with the bank’s code of ethics, a copy of which will be provided to unitholders, without charge, upon request by appointment at Bank of America Plaza, 17^th Floor, 901 Main Street, Dallas, Texas 75202.

Item 11.

Executive Compensation

The trustee received the following annual compensation from 2009 through 2011 as specified in the trust indenture:


Name and Principal Position	Year		Other Annual Compensation (1)
U.S. Trust, Bank of America		2011		$ 16,901
Private Wealth Management, Trustee		2010		8,571
		2009		5,871

(1)

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

Item 12.

Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters

The trust has no equity compensation plans.

(a) Security Ownership of Certain Beneficial Owners. The trustee is not aware of any person who beneficially owns more than 5% of the outstanding units.

(b) Security Ownership of Management. The trust has no directors or executive officers. As of January 24, 2012 Bank of America, N.A. owned, in various fiduciary capacities, 217,820 units with a shared right to vote 196,443 of these units and no right to vote 21,377 of these units. Bank of America, N.A. disclaims any beneficial interests in these units. The number of units reflected in this paragraph includes units held by all branches of Bank of America, N.A.

(c) Changes in Control. The trustee knows of no arrangements which may subsequently result in a change in control of the trust.

Item 13.

Certain Relationships and Related Transactions, and Director Independence

In computing net profits income paid to the trust for the 75% net profits interests, XTO Energy deducts an overhead charge as reimbursement for costs associated with monitoring these interests. This charge at December 31, 2011 was $34,202 per month, or $410,424 annually (net to the trust of $307,818 annually). Included in this monthly overhead charge is a charge XTO Energy deducts as operator of the Penwell Unit and ExxonMobil deducts as operator of the Hewitt Unit. As of December 31, 2011 overhead attributable to the Penwell Unit was $2,656 per month, or $31,872 annually (net to the trust of $23,904 annually) and overhead attributable to the Hewitt Unit was $4,507 per month, or $54,084 annually (net to the trust of $40,563 annually). These overhead charges are subject to annual adjustment based on an oil and gas industry index.

See Item 11, Executive Compensation, for the remuneration received by the trustee from 2009 through 2011 and Item 12(b), Security Ownership of Management, for information concerning units owned by the trustee, in various fiduciary capacities.

As noted in Item 10, Directors, Executive Officers and Corporate Governance, the trust has no directors, executive officers or audit committee. The trustee is a corporate trustee which may be removed, with or without cause, by the affirmative vote of the holders of a majority of all the units then outstanding.

Item 14.

Principal Accountant Fees and Services

Fees for services performed by PricewaterhouseCoopers LLP and KPMG LLP for the years ended December 31, 2011 and 2010 are:


	2011		2010
Audit fees-KPMG (a)	$	57,700	$	79,900
Audit fees-PwC		50,000		—
Audit-related fees		—		—
Tax fees		—		—
All other fees		—		—

	$	107,700	$	79,900

(a)

KPMG LLP served as the trust’s independent registered public accounting firm through July 7, 2011, and was replaced by PricewaterhouseCoopers LLP effective on that date.

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 and KPMG LLP.

PART IV

Item 15.

Exhibits and Financial Statement Schedules

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

Financial Statements (included in Item 8 of this report)

Report of Independent Registered Public Accounting Firm

Statements of Assets, Liabilities and Trust Corpus at December 31, 2011 and 2010

Statements of Distributable Income for the years ended December 31, 2011, 2010 and 2009

Statements of Changes in Trust Corpus for the years ended December 31, 2011, 2010 and 2009

Notes to Financial Statements

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.

Exhibits



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

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

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

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



	(31)			Rule 13a-14(a)/15d-14(a) Certification

	(32)			Section 1350 Certification

	(99.1)			Miller and Lents, Ltd. Report

Copies of the above Exhibits are available to any unitholder, at the actual cost of reproduction, upon written request to the trustee, U.S. Trust, Bank of America Private Wealth Management, P.O. Box 830650, Dallas, Texas 75283-0650.

SIGNATURES

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


	CROSS TIMBERS ROYALTY TRUST By BANK OF AMERICA, N.A., TRUSTEE

	BY	/S/ NANCY G. WILLIS
		Nancy G. Willis Vice President

	EXXON MOBIL CORPORATION

Date: February 29, 2012	BY	/S/ PATRICK T. MULVA
		Patrick T. Mulva Vice President and Controller

(The trust has no directors or executive officers.)

CROSS TIMBERS ROYALTY TRUST - FORM 10-K - February 29, 2012

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