Edgar Filing: CROSS TIMBERS ROYALTY TRUST

Form 10-K

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, 2007		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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K 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 29, 2007 (the last business day of its most recently completed second fiscal quarter), held by non-affiliates of the registrant on that date was approximately $241 million.

At February 25, 2008, 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:

2007 Annual Report to Unitholders—Part II

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.

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.” During 1996 and 1997, XTO Energy purchased 1,360,000 units on the open market. On September 18, 2003, XTO Energy distributed all of the 1,360,000 trust units it owned as a dividend to its common stockholders. XTO Energy currently is not a unitholder of the trust.

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, 2007 was $25,966 ($19,474 net to the trust). XTO Energy also deducts an overhead charge as operator of the Penwell Unit. As of December 31, 2007, monthly overhead attributable to the Penwell Unit was $2,628 ($1,971 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.

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, following its acquisition of an additional interest in this unit in August 2004. XTO Energy’s original interest in the Penwell Unit is one of the properties underlying the Texas 75% net profits interests. Other than these properties, XTO Energy does 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, and

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 69% of the net profits income received by the trust during 2007, as well as 53% of the estimated proved reserves of the net profits interests at December 31, 2007 (based on estimated future net cash flows using year-end oil and gas prices), 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.

Item 1A.

Risk Factors

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

The following discussion of risk factors should be read in conjunction with the financial statements and related notes included in the trust’s annual report to unitholders for the year ended December 31, 2007. Because of these and other factors, past financial performance should not be considered an indication of future performance.

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

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

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

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

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

Production expense and development costs are deducted in the calculation of the trust’s share of net proceeds from properties underlying the 75% net profits interests. Accordingly, higher or lower production

expense and development costs, without concurrent changes in revenue, will directly decrease or increase the amount received by the trust for its 75% net profits interests. If development costs and production expense for properties underlying the 75% net profits in a particular state exceed the production proceeds from the properties, the trust will not receive net 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.

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. The current operators of the underlying properties 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 depleting assets. Eventually, the properties underlying the trust’s net profits interests will cease to produce in commercial quantities and the trust will, therefore, cease to receive any net proceeds therefrom. The reduction in proved reserve quantities is a common measure of the depletion. Future maintenance and development projects on the underlying properties will affect the quantity of proved reserves. The timing and size of these projects will depend on the market prices of oil and natural gas. If XTO Energy or other operators of the properties do not implement additional maintenance and successful development projects, the future rate of production decline of proved reserves may be higher than the rate currently estimated.

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

Terrorist attacks and the threat of terrorist attacks, whether domestic or foreign, as well as the 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.

The operators of any underlying property may abandon the property, thereby terminating the related net profits interest payable to the trust.

The operators 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 the current or any future operators of the underlying properties.

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

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

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

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

The limited liability of trust unitholders is uncertain.

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

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

Drilling oil and natural gas wells, including development 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, the 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, 2007, 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. 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.

Producing Acreage, Wells and Drilling

Underlying Royalties. 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 trust’s estimated proved gas reserves from this region totaled 22.5 Bcf at December 31, 2007, 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 3,900 gross (approximately 40 net) wells, covering over 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.

Approximately 22% of the trust’s 2007 gas sales volumes were from coal seam production in the San Juan Basin. In October 2002, regulatory authorities approved increasing the density of coal seam wells drilled in the San Juan Basin from one well to two wells per 320-acre spacing unit, doubling the number of drill wells allowed. Increasing the density of coal seam wells could impact a significant portion of the trust’s acreage. XTO Energy has informed the trustee that it believes operators will continue to pursue increased density drilling, but the effect on the trust is unknown.

Most of the trust’s San Juan Basin conventional, or non-coal seam, production is from the Mesaverde formation. In 1999, this formation was approved for increased density drilling, which doubled the number of drill wells allowed to four per spacing unit. XTO Energy has advised the trustee that the trust has received net proceeds from additional Mesaverde wells in recent years and that it believes operators will continue to further develop the Mesaverde formation underlying the net profits interests.

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 462,000 gross (approximately 26,000 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.

Underlying Working Interest Properties. The underlying working interest properties, detailed below, are developed properties undergoing secondary or tertiary recovery operations:


			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	ExxonMobil Corporation	11.3	%	9.9	%
Wildcat Jim Penn	Carter/Oklahoma	Noble Energy Production, Inc.	8.6	%	7.5	%
South Graham Deese	Carter/Oklahoma	Lamamco Drilling Company	9.2	%	8.7	%

The underlying working interest properties consist of 60,154 gross (2,290 net) producing acres. As of December 31, 2007, there were 1,527 gross (70.6 net) productive oil wells and no wells in process of drilling on these properties. Total wells drilled were eleven gross (0.4 net) wells in 2007, nine gross (0.2 net) wells in 2006 and five gross (0.4 net) wells in 2005.

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 the three years ended December 31, 2007 were as follows:


	90% Net Profits Interests			75% Net Profits Interests			Total
	2007	2006	2005	2007	2006	2005	2007	2006	2005
Production

Underlying Properties

Oil—Sales (Bbls)	72,140	80,992	69,784	174,826	189,120	200,741	246,966	270,112	270,525
Average per day (Bbls)	198	222	191	479	518	550	677	740	741
Gas—Sales (Mcf)	2,288,853	2,577,732	2,157,785	79,064	88,745	94,576	2,367,917	2,666,477	2,252,361
Average per day (Mcf)	6,271	7,062	5,912	216	243	259	6,487	7,305	6,171

Net Profits Interests

Oil—Sales (Bbls)	62,547	69,469	60,068	48,760	73,598	85,630	111,307	143,067	145,698
Average per day (Bbls)	171	190	164	134	202	235	305	392	399
Gas—Sales (Mcf)	2,053,924	2,300,325	1,925,342	18,955	29,278	40,234	2,072,879	2,329,603	1,965,576
Average per day (Mcf)	5,627	6,302	5,275	52	80	110	5,679	6,382	5,385

Average Sales Price
Oil (per Bbl)	$59.95	$58.62	$50.34	$59.60	$59.23	$49.47	$59.70	$59.05	$49.70
Gas (per Mcf)	$8.13	$8.97	$7.87	$4.70	$3.63	$5.09	$8.01	$8.79	$7.76

Nonproducing Acreage

The underlying nonproducing royalties contain approximately 200,000 gross (approximately 3,000 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.

Oil and Natural Gas Reserves

General

Miller and Lents, Ltd., independent petroleum engineers, has estimated oil and gas reserves attributable to the underlying properties as of December 31, 2007, 2006, 2005 and 2004. 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.

The standardized measure of discounted future net cash flows and changes in such discounted cash flows as presented below are prepared using assumptions required by the Financial Accounting Standards Board. Such assumptions include the use of year-end prices for oil and gas and year-end costs for estimated future development and production expenditures to produce the proved reserves. Because natural gas prices are influenced by seasonal demand, use of year-end prices, as required by the Financial Accounting Standards Board, may not be the most representative in estimating future revenues or reserve data. Future net cash flows are discounted at an annual rate of 10%. No provision is included for federal income taxes since future net cash flows are not subject to taxation at the trust level.

Estimated costs to plug and abandon wells on the underlying working interest properties at the end of their productive lives have not been deducted from cash flows since this is not a legal obligation of the trust. These costs are the legal obligation of XTO Energy as the owner of the underlying working interests and will only be deducted from net proceeds payable to the trust if net proceeds from the related conveyance exceed such costs when paid, subject to excess cost carryforward provisions as described under Item 1.

Year-end oil prices used to determine the standardized measure were based on a West Texas Intermediate crude oil posted price of $92.70 per Bbl in 2007, $57.75 per Bbl in 2006, $57.75 per Bbl in 2005 and $40.25 per Bbl in 2004. The year-end weighted average realized gas prices used to determine the standardized measure were $6.41 per Mcf in 2007, $5.01 per Mcf in 2006, $7.70 per Mcf in 2005 and $5.14 per Mcf in 2004.

Proved Reserves


	Net Profits Interests
(in thousands)	90% Net Profits Interests				75% Net Profits Interests				Total				Underlying Properties
	Oil (Bbls)		Gas (Mcf)		Oil (Bbls)		Gas (Mcf)		Oil (Bbls)		Gas (Mcf)		Oil (Bbls)		Gas (Mcf)
Balance, December 31, 2004	630.9		29,628.5		1,071.7		465.6		1,702.6		30,094.1		3,457.4		34,155.8
Extensions, additions and discoveries	6.8		702.7		-0-		-0-		6.8		702.7		7.6		780.6
Revisions of prior estimates	(76.7	)	162.3		204.1		79.1		127.4		241.4		104.9		257.6
Production	(60.1	)	(1,925.4	)	(85.6	)	(40.2	)	(145.7	)	(1,965.6	)	(270.5	)	(2,252.4	)

Balance, December 31, 2005	500.9		28,568.1		1,190.2		504.5		1,691.1		29,072.6		3,299.4		32,941.6
Extensions, additions and discoveries	11.3		873.2		-0-		-0-		11.3		873.2		12.6		970.9
Revisions of prior estimates	87.4		647.3		(247.7	)	(135.4	)	(160.3	)	511.9		(56.6	)	635.1
Production	(69.5	)	(2,300.3	)	(73.6	)	(29.3	)	(143.1	)	(2,329.6	)	(270.1	)	(2,666.5	)

Balance, December 31, 2006	530.1		27,788.3		868.9		339.8		1,399.0		28,128.1		2,985.3		31,881.1
Extensions, additions and discoveries	10.1		1,151.3		-0-		-0-		10.1		1,151.3		11.2		1,279.0
Revisions of prior estimates	27.9		316.5		411.7		135.7		439.6		452.2		356.1		409.7
Production	(62.5	)	(2,053.9	)	(48.8	)	(19.0	)	(111.3	)	(2,072.9	)	(247.0	)	(2,367.9	)

Balance, December 31, 2007	505.6		27,202.2		1,231.8		456.5		1,737.4		27,658.7		3,105.6		31,201.9

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 year-end prices and costs. See “General” above. During 2007, payout occurred under the reversion agreement in which 25% of XTO Energy’s interest in certain underlying royalties were transferred to a third party when payout occurred. As a result, the December 31, 2007 proved reserves for the underlying properties attributable to the 90% net profits interest have been reduced to reflect payout. Previously, December 31, 2005 and 2006, proved reserves for the underlying properties and attributable to the 90% net profits interests were reduced to reflect anticipated payout under the reversion agreement. See “Reversion Agreement” below.

Proved Developed Reserves


	Net Profits Interests
(in thousands)	90% Net Profits Interests		75% Net Profits Interests		Total		Underlying Properties
	Oil (Bbls)	Gas (Mcf)	Oil (Bbls)	Gas (Mcf)	Oil (Bbls)	Gas (Mcf)	Oil (Bbls)	Gas (Mcf)
December 31, 2004	630.9	29,210.5	1,071.7	465.6	1,702.6	29,676.1	3,457.4	33,691.3

December 31, 2005	500.9	28,568.1	1,190.2	504.5	1,691.1	29,072.6	3,299.4	32,941.6

December 31, 2006	530.1	27,788.3	866.9	335.3	1,397.0	28,123.6	2,974.8	31,857.4

December 31, 2007	505.6	27,202.2	1,229.1	450.3	1,734.7	27,652.5	3,098.5	31,185.8

Standardized Measure of Discounted Future Net Cash Flows from Proved Reserves


(in thousands)	90% Net Profits Interests									75% Net Profits Interests									Total
	December 31									December 31									December 31
	2007			2006			2005			2007			2006			2005			2007			2006			2005
*Net Profits Interests*
Future cash inflows	$	220,416		$	166,093		$	250,137		$	110,659		$	48,802		$	68,872		$	331,075		$	214,895		$	319,009
Future production taxes		(17,674	)		(14,698	)		(21,274	)		(7,240	)		(3,577	)		(4,828	)		(24,914	)		(18,275	)		(26,102	)

Future net cash flows		202,742			151,395			228,863			103,419			45,225			64,044			306,161			196,620			292,907
10% discount factor		(106,209	)		(77,841	)		(120,548	)		(54,651	)		(21,391	)		(31,749	)		(160,860	)		(99,232	)		(152,297	)

Standardized measure	$	96,533		$	73,554		$	108,315		$	48,768		$	23,834		$	32,295		$	145,301		$	97,388		$	140,610


*Underlying Properties*

Future cash inflows																			$	473,361		$	319,605		$	437,017
Future production costs																				(110,200	)		(91,088	)		(97,333	)

Future net cash flows																				363,161			228,517			339,684
10% discount factor																				(190,878	)		(115,013	)		(176,274	)

Standardized measure																			$	172,283		$	113,504		$	163,410

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


	90% Net Profits Interests									75% Net Profits Interests									Total
	2007			2006			2005			2007			2006			2005			2007			2006			2005
*Net Profits Interests*
Standardized measure, January 1	$	73,554		$	108,315		$	78,856		$	23,834		$	32,295		$	21,735		$	97,388		$	140,610		$	100,591
Extensions, additions and discoveries		3,788			2,626			2,647			-0-			-0-			-0-			3,788			2,626			2,647
Accretion of discount		6,133			9,036			6,615			2,101			2,845			1,909			8,234			11,881			8,524
Revisions of prior estimates, changes in price and other		30,411			(25,383	)		35,649			25,669			(7,090	)		12,834			56,080			(32,473	)		48,483
Net profits income		(17,353	)		(21,040	)		(15,452	)		(2,836	)		(4,216	)		(4,183	)		(20,189	)		(25,256	)		(19,635	)

Standardized measure, December 31	$	96,533		$	73,554		$	108,315		$	48,768		$	23,834		$	32,295		$	145,301		$	97,388		$	140,610


*Underlying Properties*

Standardized measure, January 1																			$	113,504		$	163,410		$	116,598

Revisions:
Prices and costs																				66,041			(39,501	)		57,635
Quantity estimates																				4,117			2,645			(266	)
Accretion of discount																				9,610			13,834			9,895
Future development costs																				(2,151	)		(783	)		(642	)
Other																				16			(19	)		(6	)

Net revisions																				77,633			(23,824	)		66,616
Extensions, additions and discoveries																				4,209			2,918			2,942
Production																				(25,262	)		(29,724	)		(23,388	)
Development costs																				2,199			724			642

Net change																				58,779			(49,906	)		46,812

Standardized measure, December 31																			$	172,283		$	113,504		$	163,410

Reversion Agreement

Certain of the properties underlying the 90% net profits interests were subject to a reversion agreement between XTO Energy and an unrelated party. The agreement called for XTO Energy to transfer 25% of its interest in those properties to the third party when net amounts received by XTO Energy from the properties subject to the agreement equal the purchase price of the properties plus a 1% per month return on the unrecouped purchase price, known as payout. At the time payout occurred, net proceeds payable to the trust and trust distributions to unitholders were reduced. XTO Energy informed the trustee that payout occurred effective with the July 2007 distribution, which was paid on August 14, 2007, thereby reducing the July 2007 distribution and all future distributions by approximately 5%.

Regulation

Natural Gas Regulation

The interstate transportation and sale for resale of natural gas is subject to federal regulation, including transportation rates charged 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. 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 new regulations to implement the Energy Policy Act. While natural gas prices are currently unregulated, Congress historically has been active in the area of natural gas regulation. It is impossible to predict whether new legislation to regulate natural gas might be proposed, what proposals, if any, might actually be enacted by Congress or the various state legislatures, and what effect, if any, such proposals might have on the operations of the underlying properties.

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. We cannot predict the impact of future government regulation on any natural gas facilities.

State Regulation

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

State Tax Withholding

Several states have enacted legislation to require state income tax withholding from nonresident recipients of oil and gas proceeds. After consultation with its state tax counsel, XTO Energy has advised the trustee that it believes the trust is not subject to these withholding requirements. However, regulations are subject to change by the various states, which could change the conclusion. Should the trust be required to withhold state taxes, distributions to the unitholders would be reduced by the required amount, subject to the unitholder’s right to file a state tax return to claim any refund due.

In May 2006, the State of Texas passed legislation to implement a new margin tax of 1% to be imposed on revenues less certain costs, as specified in the legislation, generated from Texas activities beginning in 2007. Entities subject to the tax generally include trusts, unless otherwise exempt, and various other types of entities. Trusts that meet statutory requirements are generally exempt from the margin tax as “passive entities.” Recent legislative action has clarified that the trust is exempt from margin tax as a passive entity. However, each unitholder that is a business entity subject to the margin tax is generally required to include its share of the trust’s revenues in its margin tax computation.

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

Other Regulation

The petroleum industry is also subject to compliance with various other federal, state and local regulations and laws, including, but not limited to, regulations and laws relating to environmental protection, occupational safety, resource conservation and equal employment opportunity. XTO Energy has advised the trustee that it does not believe that compliance with these laws will have any material adverse effect upon the unitholders.

Item 3.

Legal Proceedings

Certain of the underlying properties are involved in various lawsuits and certain governmental proceedings arising in the ordinary course of business. XTO Energy has advised the trustee that it does not believe that the ultimate resolution of these claims will have a material effect on trust annual distributable income, financial position or liquidity.

Item 4.

Submission of Matters to a Vote of Security Holders

No matters were submitted to a vote of unitholders during 2007.

PART II

Item 5.

Market for Units of the Trust, Related Security Holder Matters and Trust Purchases of Units

The section entitled “Units of Beneficial Interest” in the trust’s annual report to unitholders for the year ended December 31, 2007 is incorporated herein by reference.

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
	2007		2006		2005		2004		2003
Net Profits Income	$	20,189,267	$	25,767,154	$	20,607,961	$	15,222,417	$	12,944,047
Distributable Income		19,805,724		25,448,178		20,267,436		14,924,058		12,688,746
Distributable Income per Unit		3.300954		4.241363		3.377906		2.487343		2.114791
Distributions per Unit		3.300954		4.241363		3.377906		2.487343		2.114791
Total Assets at Year-End		20,147,900		21,655,260		23,318,733		24,284,184		25,660,147

Item 7.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

The “Trustee’s Discussion and Analysis” of financial condition and results of operations for each of the years in the three-year period ended December 31, 2007 in the trust’s annual report to unitholders for the year ended December 31, 2007 is incorporated herein by reference.

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.

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, 2007, other than the December distribution payable to unitholders in January 2008, 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	$	1,760,148	$	1,760,148	$	—	$	—	$	—

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, 2007, this monthly charge was $25,966 ($19,474 net to the trust). XTO Energy also deducts an overhead charge as operator of the Penwell Unit. As of December 31, 2007, monthly overhead attributable to the Penwell Unit was $2,628 ($1,971 net to the trust). These overhead charges are subject to annual adjustment based on an oil and gas industry index. For further information regarding the trust’s relationship with XTO Energy, see Note 5 to Financial Statements in the trust’s annual report to unitholders for the year ended December 31, 2007.

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 in the trust’s annual report to unitholders for the year ended December 31, 2007.

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 prices at the date of the evaluation, 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 Item 2, is prepared using assumptions required by the Financial Accounting Standards Board and the Securities and Exchange Commission. Such assumptions include using year-end oil and gas prices and year-end costs for estimated future development and production expenditures. Discounted future net cash flows are calculated using a 10% rate. Changes in any of these assumptions, including consideration of other factors, could have a significant impact on the standardized measure. Accordingly, the standardized measure does not represent XTO Energy’s or the trustee’s estimated current market value of proved reserves.

Forward-Looking Statements

Certain information included in this annual report and other materials filed, or to be filed, by the trust with the Securities and Exchange Commission (as well as information included in oral statements or other written statements made or to be made by XTO Energy or the trustee) contain forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended, and Section 27A of the Securities Act of 1933, as amended, relating to the trust, operations of the underlying properties and the oil and gas industry. Such forward-looking statements may concern, among other things, development activities, future development plans, increased density drilling, maintenance projects, development, production and other costs, oil and gas prices, pricing differentials, proved reserves, amount of reduction of distributions due to payout on reversion properties, 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.

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

The financial statements of the trust and the notes thereto, together with the related reports of KPMG LLP dated February 25, 2008, appearing in the trust’s annual report to unitholders for the year ended December 31, 2007, are incorporated herein by reference.

Item 9.

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

There have been no changes in accountants and no disagreements with the trust’s independent registered public accountants on any matter of accounting principles or practices or financial statement disclosures during the two years ended December 31, 2007.

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, 2007. The effectiveness of the trust’s internal control over financial reporting as of December 31, 2007 has been audited by KPMG LLP, an independent registered public accounting firm, as stated in their report in the trust’s annual report to unitholders for the year ended December 31, 2007, which is incorporated herein by reference.

There were no changes in the trust’s internal control over financial reporting during the quarter ended December 31, 2007 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 of the Registrant and Corporate Governance

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

Section 16(a) of the Securities Exchange Act of 1934 requires that beneficial owners of more than 10% of the registrant’s equity securities file initial reports of beneficial ownership and reports of changes in beneficial ownership with the Securities and Exchange Commission and the New York Stock Exchange. The Securities and Exchange Commission has taken the position that executive officers and directors of XTO Energy must also file initial ownership reports and reports of changes in beneficial ownership. Copies of the reports must be provided to the trust. To the trustee‘s knowledge, based solely on the information furnished to the trust, the trust 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, 2007.

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 2005 through 2007 as specified in the trust indenture:


Name and Principal Position	Year	Other Annual Compensation (1)
U.S. Trust, Bank of America	2007	$	10,095
Private Wealth Management, Trustee	2006		12,884
	2005		10,304

(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 23, 2008 Bank of America, N.A. owned, in various fiduciary capacities, 51,141 units with a shared right to vote 28,161 of these units and no right to vote 22,980 of these units. Bank of America, N.A. disclaims any beneficial interests in these units. The number of units reflected in this paragraph includes units held by all branches of Bank of America, N.A.

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

Item 13.

Certain Relationships and Related Transactions, and Director Independence

In computing net profits income paid to the trust for the 75% net profits interests, XTO Energy deducts an overhead charge as reimbursement for costs associated with monitoring these interests. This charge at December 31, 2007 was $25,966 per month, or $311,592 annually (net to the trust of $233,694 annually). XTO Energy also deducts an overhead charge as operator of the Penwell Unit. As of December 31, 2007, overhead attributable to the Penwell Unit was $2,628 per month, or $31,536 annually (net to the trust of $23,652 annually). These overhead charges are subject to annual adjustment based on an oil and gas industry index.

See Item 11 for the remuneration received by the trustee from 2005 through 2007 and Item 12(b) for information concerning units owned by the trustee, in various fiduciary capacities.

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

Item 14.

Principal Accountant Fees and Services

Fees for services performed by KPMG LLP for the years ended December 31, 2007 and 2006 are:


	2007		2006
Audit fees	$	71,750	$	71,750
Audit-related fees		—		—
Tax fees		—		—
All other fees		—		—

	$	71,750	$	71,750

As referenced in Item 10, above, the trust has no audit committee, and as a result, has no audit committee pre-approval policy with respect to fees paid to KPMG LLP.

PART IV

Item 15.

Exhibits and Financial Statement Schedules

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

Financial Statements (incorporated by reference in Item 8 of this report)

Independent Registered Public Accounting Firm Reports

Statements of Assets, Liabilities and Trust Corpus at December 31, 2007 and 2006

Statements of Distributable Income for the years ended December 31, 2007, 2006 and 2005

Statements of Changes in Trust Corpus for the years ended December 31, 2007, 2006 and 2005

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.

(13)		Cross Timbers Royalty Trust annual report to unitholders for the year ended December 31, 2007



(23.1)		Consent of KPMG LLP

(23.2)		Consent of Miller and Lents, Ltd.

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

(32)		Section 1350 Certification

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

	XTO ENERGY INC.

Date: February 26, 2008	By	/s/ LOUIS G. BALDWIN
		Louis G. Baldwin Executive Vice President and Chief Financial Officer

(The trust has no directors or executive officers.)