As filed with the Securities and Exchange Commission on October 6, 2000. Registration No. 333-56983 - -------------------------------------------------------------------------------- - -------------------------------------------------------------------------------- SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 -------------- Amendment No. 1 to Form S-3 REGISTRATION STATEMENT UNDER THE SECURITIES ACT OF 1933 -------------- CROSS TIMBERS OIL COMPANY CROSS TIMBERS ROYALTY TRUST (Exact name of co-registrant as specified in (Exact name of co-registrant as specified in its charter) its charter) Delaware Texas (State or other jurisdiction of (State or other jurisdiction of incorporation or organization) incorporation or organization) 75-2347769 75-6415930 (I.R.S. Employer Identification No.) (I.R.S. Employer Identification No.) 810 Houston Street, Suite 2000 Bank of America Fort Worth, Texas 76102 P.O. Box 830650 (817) 870-2800 Dallas, Texas 75283-0650 (Address, including zip code, and telephone (214) 508-2440 number, including area code, of (Address, including zip code, and telephone registrant's principal executive offices) number, including area code, of Bob R. Simpson registrant's principal executive offices) 810 Houston Street, Suite 2000 Ron E. Hooper Fort Worth, Texas 76102 901 Main Street (817) 870-2800 Dallas, Texas 75202 (Name, address, including zip code, and (214) 508-2440 telephone number, including area code, of (Name, address, including zip code, and agent for service) telephone number, including area code, of agent for service) -------------- Copies to: F. Richard Bernasek, Esq. James M. Prince, Esq. Grant C. Lightle Kelly, Hart & Hallman, P.C. Vinson & Elkins L.L.P. Thompson & Knight L.L.P. 1700 Pacific Ave., Suite 201 Main Street, Suite 2500 2300 First City Tower 3300 Fort Worth, Texas 76102 1001 Fannin Dallas, Texas 75201 (817) 332-2500 Houston, Texas 77002 (214) 969-1700 (713) 758-2222 -------------- Approximate date of commencement of proposed sale to the public: As soon as practicable after this Registration Statement becomes effective. If the only securities being registered on this form are being offered pursuant to dividend or interest reinvestment plans, please check the following box. [_] If any of the securities being registered on this Form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, other than securities offered only in connection with dividend or interest reinvestment plans, check the following box. [_] If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, please check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. [_] If this Form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. [_] If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. [_] If delivery of the prospectus is expected to be made pursuant to Rule 434, please check the following box. [_] -------------- The Registrant hereby amends this Registration Statement on such date or dates as may be necessary to delay its effective date until the Registrant shall file a further amendment which specifically states that this Registration Statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933 or until this Registration Statement shall become effective on such date as the Commission, acting pursuant to said Section 8(a), may determine. - -------------------------------------------------------------------------------- - -------------------------------------------------------------------------------- ++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++ +The information in this preliminary prospectus is not complete and may be + +changed. These securities may not be sold until the registration statement + +filed with the Securities and Exchange Commission is effective. This + +preliminary prospectus is not an offer to sell nor does it seek an offer to + +buy these securities in any jurisdiction where the offer or sale is not + +permitted. + ++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++ PROSPECTUS Subject to completion, dated October 6, 2000 1,200,000 Trust Units Cross Timbers Royalty Trust ------------------------------------------------------ This is a public offering of units of beneficial interest in the Cross Timbers Royalty Trust. The offered units of Cross Timbers Royalty Trust are currently outstanding. Cross Timbers Oil Company formed the trust as a grantor trust in 1991 and is offering all of the trust units to be sold in this offering, and Cross Timbers Oil will receive all proceeds from the offering. The trust will not receive any proceeds from the offering. There is currently a public market for the trust units. The trust units are listed on the New York Stock Exchange under the symbol "CRT". On October 4, 2000, the last reported sale price of the trust units on the New York Stock Exchange was $15.69 per unit. The Trust Units. Trust units are units of beneficial ownership of the trust and represent undivided interests in the trust. They do not represent any interest in Cross Timbers Oil. The Trust. The trust owns net profits interests in oil and natural gas producing properties located in New Mexico, Texas and Oklahoma. The net profits interests entitle the trust to receive 90% for royalty properties and 75% for working interest properties of the net proceeds from the sale of production from these oil and natural gas properties owned by Cross Timbers Oil. The Trust Unitholders. As a trust unitholder, you will receive monthly distributions of cash that the trust receives for its net profits interests from the sale of oil and natural gas produced from the underlying properties. INVESTING IN THE TRUST UNITS INVOLVES RISKS. SEE "RISK FACTORS" BEGINNING ON PAGE 11.

Per Trust Unit Total ----- ------ Public offering price............................................. $ $ Underwriting discount............................................. $ $ Proceeds, before expenses, to Cross Timbers Oil................... $ $

Cross Timbers Oil has granted the underwriters a 30-day option to purchase up to an additional 160,000 trust units on the same terms and conditions as set forth above to cover over-allotments, if any. Neither the Securities and Exchange Commission nor any other regulatory body has approved or disapproved of these securities or determined that this prospectus is truthful or complete. Any representation to the contrary is a criminal offense. Lehman Brothers, on behalf of the underwriters, expects to deliver the trust units to purchasers on or about , 2000. ------------------------------------------------------ Lehman Brothers Dain Rauscher Wessels Fidelity Capital Markets a division of National Financial Services LLC October , 2000 NO DEALER, SALESPERSON OR OTHER PERSON IS AUTHORIZED TO GIVE ANY INFORMATION OR TO REPRESENT ANYTHING NOT CONTAINED IN THIS PROSPECTUS. YOU MUST NOT RELY ON ANY UNAUTHORIZED INFORMATION OR REPRESENTATIONS. THIS PROSPECTUS IS AN OFFER TO SELL THE TRUST UNITS OFFERED HEREBY, BUT ONLY UNDER CIRCUMSTANCES AND IN JURISDICTIONS WHERE IT IS LAWFUL TO DO SO. THE INFORMATION CONTAINED IN THIS PROSPECTUS IS CURRENT ONLY AS OF ITS DATE. ---------------- TABLE OF CONTENTS

Page ---------------- Prospectus Summary............................................. 3 Risk Factors................................................... 11 Forward-Looking Statements..................................... 15 Use of Proceeds................................................ 15 Price Range of Trust Units and Distributions................... 15 Cross Timbers Oil Company...................................... 16 The Trust...................................................... 16 The Underlying Properties...................................... 16 Computation of Net Proceeds.................................... 28 Federal Income Tax Consequences................................ 31 State Tax Considerations....................................... 36 ERISA Considerations........................................... 37 Description of the Trust Indenture............................. 38 Description of the Trust Units................................. 42 Selling Trust Unitholder....................................... 45 Underwriting................................................... 45 Legal Matters.................................................. 47 Experts........................................................ 47 Available Information.......................................... 48 Glossary of Certain Oil and Natural Gas Terms.................. 49 Summary Reserve Reports........................................ Exhibits A and B

2 PROSPECTUS SUMMARY This summary may not contain all of the information that is important to you. To understand this offering fully, you should read the entire prospectus carefully, including the risk factors and the financial statements and notes to those statements. You will find definitions for terms relating to the oil and natural gas business in "Glossary of Certain Oil and Natural Gas Terms." Miller and Lents, Ltd., an independent engineering firm, provided the estimates of proved oil and natural gas reserves at December 31, 1999 included in this prospectus. These estimates are contained in summaries by Miller and Lents of the reserve reports as of December 31, 1999, for the underlying properties described below and for the net profits interests in the underlying properties held by the trust. These summaries are located at the back of this prospectus as Exhibits A and B and are referred to in the prospectus as the reserve report. Cross Timbers Royalty Trust Cross Timbers Royalty Trust was formed in 1991 by Cross Timbers Oil Company. Cross Timbers Oil conveyed to the trust net profits interests in oil and natural gas producing properties located primarily in the San Juan Basin of New Mexico, the Permian Basin of West Texas and in Oklahoma. We refer to Cross Timbers Oil's interests in these properties as the underlying properties. The net profits interests entitle the trust to receive 90% of net proceeds from the sale of oil and natural gas from the underlying properties that are included in each of three royalty interest conveyances, and 75% of net proceeds from the sale of oil and natural gas from the underlying properties that are included in each of two working interest conveyances. Each month Cross Timbers Oil collects cash received from the sale of production and deducts property and production taxes from all underlying properties, and deducts development costs, production costs and overhead from only the underlying properties included in the two working interest conveyances, and distributes net proceeds to the trust. Net proceeds payable to the trust depend upon production quantities, sales prices of oil and natural gas and costs to develop and produce the oil and natural gas. If at any time costs should exceed gross proceeds, neither the trust nor the trust unitholders would be liable for the excess costs. However, the trust would not receive any net proceeds until future net proceeds exceed the total of those excess costs, plus interest at the prime rate. Cross Timbers Oil calculates the net proceeds separately for each of the five conveyances of net profits interests in the underlying properties. Any excess costs for underlying properties covered by one conveyance will not reduce net proceeds calculated for properties covered by another conveyance. The trust makes monthly distributions of substantially all of its income to holders of its trust units. On your federal income tax returns, you will be required to include your proportionate share of trust income. In addition, you will be entitled to claim deductions for depletion relating to production from the underlying properties and for your share of trust administrative expense. The deductions will permit you to defer taxes on a significant portion of the income you receive from the trust. Cross Timbers Oil's Ownership Interests in the Trust and the Underlying Properties The underlying properties include royalty and overriding royalty interests and working interests. Working interest properties bear the costs of exploration, production and development while royalty and overriding royalty interests do not. Net profits interests in the underlying properties were 3 conveyed to the trust by Cross Timbers Oil in five separate property groups. Three are 90% net profits interests in royalty and overriding royalty interest groups, one in each of New Mexico, Oklahoma and Texas. The remaining two are 75% net profits interests in working interest groups in each of Oklahoma and Texas. Cross Timbers Oil's retained interest in the underlying properties entitles it to retain all net proceeds from production after deducting the percentage of net proceeds payable to the trust. Effectively, this entitles Cross Timbers Oil to 10% for the 90% net profits interests properties and 25% for the 75% net profits interests properties of the net proceeds from production. Cross Timbers Oil is under no obligation to continue to own the underlying properties, but currently intends to do so. The following chart shows the relationship of Cross Timbers Oil, the trust and the public trust unitholders after this offering, assuming full exercise of the underwriters' overallotment option. [FLOW CHART SHOWING THE RELATIONSHIP AMONG CROSS TIMBERS, THE TRUST AND THE PUBLIC TRUST UNITHOLDERS APPEARS HERE] Management of Cross Timbers Oil has been involved in the formation of four publicly traded royalty trusts. The trusts are the Hugoton Royalty Trust formed in 1998, the Cross Timbers Royalty Trust formed in 1991, and the Permian Basin Royalty Trust and the San Juan Basin Royalty Trust both formed in 1980. Cross Timbers Oil may form additional royalty trusts with other properties. The Underlying Properties The producing underlying properties are long-lived properties, generally with well-established production histories operated by major oil companies or large independent energy companies. The underlying properties comprise Cross Timbers Oil's interest in over 2,900 properties acquired by Cross Timbers Oil from 1986 through 1990. As of December 31, 1999, approximately 72% of the discounted estimated future net revenues attributable to the net profits interests is allocable to the 90% net profits interests in royalty properties and 28% is allocable to the 75% net profits interests in working interests properties. Estimated proved reserves attributable to the underlying properties are approximately 40% oil and 60% natural gas, based on the discounted present value of estimated future net revenues as of December 31, 1999. 4 Long Life of Properties The average productive life of proved reserves of the underlying properties is relatively long compared to the average life of domestic proved reserves. The productive lives of producing oil and natural gas properties are often compared using their reserve-to-production index. This index is calculated by dividing total estimated proved reserves of the property by annual production for the prior 12 months. The reserve-to-production index for the underlying properties at December 31, 1999 was 12 years. This compares favorably to an average index of 9.2 years for U.S. oil and natural gas properties of publicly reporting companies at year-end 1999. Because production rates naturally decline over time, the index is not a useful estimate of how long properties should economically produce. Based on the reserve report, economic production from the underlying properties is expected for at least 35 more years. High Percentage of Proved Developed Reserves Proved developed reserves are the most valuable and lowest risk category of reserves because their production requires no significant future development costs. Proved developed reserves represent approximately 96% of the discounted present value of estimated future net revenues from the underlying properties. Effect of Development The underlying properties are Cross Timbers Oil's undivided interests in oil and natural gas leases and the production from existing and future wells on those leases. If the operators successfully drill additional wells on acreage covered by these leases or successfully conduct other development activities, those activities will enhance production from the underlying properties. Since the trust units were initially sold to the public in February 1992, 50% of production sold through December 31, 1999 was replaced by increased proved reserves. The trust will benefit from increased production free of costs on the 90% net profits interests, but net of 75% of the development costs on the 75% net profits interests. There can be no assurances that the operators will continue to develop the underlying properties. Cross Timbers Oil operates an immaterial amount of the underlying properties, based on the discounted present value of estimated future net revenues. Development History Cross Timbers Oil estimates that royalty properties in the San Juan Basin underlying certain of the 90% net profits interests include more than 2,000 gross (approximately 30 net) wells on 60,000 gross acres. Most of these wells are operated by Amoco Production Company and Burlington Resources Oil & Gas Company. Gas was first produced in the San Juan Basin in 1921, and today it is considered to be the second largest gas producing area in the United States. The San Juan Basin is characterized by multiple productive geologic formations, including the Fruitland Coal, Pictured Cliffs, Mesaverde and Dakota. Development has taken place in several phases, including 160-acre infill drilling of the Mesaverde starting in 1977 and of the Dakota starting in 1979. The most recent development phase from 1980 to the present has been in the Fruitland Coal because of the incentive of the Section 29 federal income tax credit applicable to gas produced from coal seam gas wells drilled prior to January 1, 1993. However, advanced technology and improved operating procedures have allowed further Fruitland Coal development after the expiration of the tax credit drilling eligibility period. Operators have reported continued development in additional formations and the use of enhanced recovery techniques in existing productive formations, but it is not known if this activity has affected or will affect Trust reserves or distributions. 5 The underlying properties from which the 75% net profits interests were carved are working interests in developed properties which have been undergoing systematic secondary and enhanced recovery operations. Any increase or decrease in costs from such activities directly affects the net proceeds payable to the trust under the applicable 75% net profits interests. See "Risk Factors-- Development Costs." For a summary of development and operating costs over the last five years associated with the working interest properties, see "Selected Financial Data." Ownership of the Underlying Properties Cross Timbers Oil currently owns the underlying properties, subject to the net profits interests, and is entitled to any proceeds received in excess of the net proceeds paid to the trust. Cross Timbers Oil's duties under the conveyances creating the net profits interests are ministerial in nature. For the 90% net profits interests, Cross Timbers Oil is required to receive payments from the sale of production from the underlying properties, deduct taxes and pay 90% of such amount to the trustee for distribution to trust unitholders. For the 75% net profits interests, Cross Timbers Oil is required to receive payments representing its share of the sale of production, deduct taxes and costs invoiced by the operators of such underlying properties and pay 75% of the net amount to the trust. Cross Timbers Oil may sell the underlying properties, subject to and burdened by the net profits interests, without the consent of the trustee or the trust unitholders. Following any such sale, the purchaser of the underlying properties would be required to calculate and pay to the trust the net proceeds and to otherwise perform all of Cross Timbers Oil's duties under the conveyances. Cross Timbers Oil does not currently intend to sell the underlying properties. Recent Developments The trust reported third quarter 2000 royalty income of $3,394,310. Distributable income for the quarter was $3,346,332 or $0.557722 per unit of beneficial interest. The distributable income for the quarter includes approximately $.04 per unit related to revenue overpaid to the trust for the distribution declared in September. Cross Timbers Oil expects the correction of this overpayment to affect distributable income in the fourth quarter 2000. 6 Proved Reserves Based on the reserve report as of December 31, 1999, estimated proved reserves of the underlying properties are approximately 40% oil and 60% natural gas on a Mcfe basis. The following table provides estimated proved oil and natural gas reserves for the underlying properties, and the estimated proved reserves and undiscounted and discounted estimated future net revenues for the net profits interests. Proved reserves in the table are based on oil and natural gas prices realized by Cross Timbers Oil as of December 31, 1999, which averaged $23.93 per Bbl of oil (based on a West Texas Intermediate posted price of $22.75), and $2.19 per Mcf of natural gas. Gas equivalents in the table are the sum of Mcf of gas and the Mcfe of the stated Bbls of oil, calculated on the basis that one Bbl of oil is the energy equivalent of six Mcf of natural gas. The amounts of estimated future net revenues from proved reserves shown in the table are before income taxes. Discounted future net revenues are based on a discount rate of 10%, which is the rate required by the Securities and Exchange Commission for presentation of proved reserves. Reserve estimates are subject to revision.

Underlying Properties Net Profits Interests --------------- --------------------------------------- Estimated Future Net Revenues from Proved Reserves Proved Reserves Proved Reserves --------------- --------------- ----------------------- Natural Natural Oil Gas Oil Gas (MBbls) (MMcf) (MBbls) (MMcf) Undiscounted Discounted ------- ------- ------- ------- ------------ ---------- (in thousands, except per unit data) 90% Net Profits Interests San Juan Basin Conventional.......... 82 26,531 74 23,878 $ 55,075 $23,281 Coal seam............. -- 5,992 -- 5,393 8,681 5,642 ----- ------ ----- ------ -------- ------- Total............... 82 32,523 74 29,271 63,756 28,923 Other New Mexico....... 146 346 131 291 3,459 2,063 Texas.................. 497 4,235 444 3,619 17,831 9,799 Oklahoma............... 87 2,057 70 1,744 5,105 2,793 ----- ------ ----- ------ -------- ------- Total............... 812 39,161 719 34,925 90,151 43,578 ----- ------ ----- ------ -------- ------- 75% Net Profits Interests (a) Texas.................. 1,921 848 892 394 20,881 9,718 Oklahoma............... 1,727 589 587 194 13,302 7,330 ----- ------ ----- ------ -------- ------- Total............... 3,648 1,437 1,479 588 34,183 17,048 ----- ------ ----- ------ -------- ------- Total Net Profits Interests.............. 4,460 40,598 2,198 35,513 $124,334 $60,626 ===== ====== ===== ====== ======== ======= Per Trust Unit.......... $ 20.72 $ 10.10 ======== =======

- -------- (a) Proved reserves for the 75% net profits interests owned by the trust are calculated by subtracting from 75% of proved reserves of the underlying properties that are working interests, reserve quantities of a sufficient value to pay 75% of the future estimated costs, before overhead and trust administrative expenses, that are deducted in calculating net proceeds. Accordingly, proved reserves for the 75% net profits interests reflect quantities that are calculated after reductions for future costs and expenses based on price and cost assumptions used in the reserve estimates. 7 Selected Financial Data The following table provides oil and natural gas sales volumes and summary financial data relating to the trust and underlying properties for each of the years in the five-year period ended December 31, 1999 and for each of the six- month periods ended June 30, 1999 and 2000.

Six Months Ended June 30 Year Ended December 31 (Unaudited) -------------------------------------------------- -------------------- 1995 1996 1997 1998 1999 1999 2000 --------- --------- --------- --------- --------- --------- --------- (in thousands, except per unit data) Statement of Distributable Income Data Royalty income.......... $ 5,740 $ 8,270 $ 10,550 $ 7,080 $ 6,691 $ 2,693 $ 4,830 Interest income......... 8 11 16 10 11 4 10 --------- --------- --------- --------- --------- --------- --------- Total income.......... 5,748 8,281 10,566 7,090 6,702 2,697 4,840 Administration expense.. 170 204 159 163 152 85 115 --------- --------- --------- --------- --------- --------- --------- Distributable income.... $ 5,578 $ 8,077 $ 10,407 $ 6,927 $ 6,550 $ 2,612 $ 4,725 ========= ========= ========= ========= ========= ========= ========= Distributable income per trust unit............. $0.929705 $1.346162 $1.734541 $1.154555 $1.091635 $0.435295 $0.787571 ========= ========= ========= ========= ========= ========= ========= Section 29 tax credit per trust unit......... $0.180246 $0.189374 $0.212340 $0.162287 $0.157564 $0.081657 $ 0.063(a) ========= ========= ========= ========= ========= ========= ========= Computation of Royalty Income 90% Net Profits Interests Revenues Oil sales.............. $ 1,380 $ 1,663 $ 1,853 $ 1,412 $ 1,347 $ 550 $ 1,094 Natural gas sales...... 4,410 6,414 8,798 6,955 7,133 3,008 4,270 --------- --------- --------- --------- --------- --------- --------- Total................. 5,790 8,077 10,651 8,367 8,480 3,558 5,364 --------- --------- --------- --------- --------- --------- --------- Costs--Taxes, transportation and other................. 682 777 967 849 1,444 569 879 --------- --------- --------- --------- --------- --------- --------- Net proceeds.......... 5,108 7,300 9,684 7,518 7,036 2,989 4,485 --------- --------- --------- --------- --------- --------- --------- Royalty Income--90% net profits interests..... 4,597 6,570 8,716 6,766 6,332 2,690 4,036 --------- --------- --------- --------- --------- --------- --------- 75% Net Profits Interests Revenues Oil sales.............. 5,339 6,461 6,289 3,844 3,842 1,436 3,224 Natural gas sales...... 154 212 226 139 127 43 118 --------- --------- --------- --------- --------- --------- --------- Total................. 5,493 6,673 6,515 3,983 3,969 1,479 3,342 --------- --------- --------- --------- --------- --------- --------- Costs Taxes, transportation and other............. 599 535 556 347 165 61 311 Production expense..... 2,620 2,707 2,645 2,580 2,388 1,195 1,241 Development costs...... 750 1,164 869 1,143 736 441 348 Net (excess costs) excess cost recovery and interest.......... -- -- -- (505) 201 (222) 384 --------- --------- --------- --------- --------- --------- --------- Total................. 3,969 4,406 4,070 3,565 3,490 1,475 2,284 --------- --------- --------- --------- --------- --------- --------- Net proceeds.......... 1,524 2,267 2,445 418 479 4 1,058 --------- --------- --------- --------- --------- --------- --------- Royalty Income--75% net profits interests..... 1,143 1,700 1,834 314 359 3 794 --------- --------- --------- --------- --------- --------- --------- Total Royalty Income.. $ 5,740 $ 8,270 $ 10,550 $ 7,080 $ 6,691 $ 2,693 $ 4,830 ========= ========= ========= ========= ========= ========= ========= Oil and Gas Sales Volumes Net Profits Interests Oil sales (Bbls)....... 149 168 177 105 98 39 72 Natural gas sales (Mcf)................. 2,992 3,829 3,878 3,019 3,163 1,502 1,359 Underlying Properties Oil sales (Bbls)....... 441 437 424 392 349 175 169 Natural gas sales (Mcf)................. 3,513 4,385 4,419 3,502 3,643 1,735 1,567 Average Prices Oil per Bbl............ $ 15.25 $ 18.60 $ 19.20 $ 13.40 $ 14.88 $ 11.36 $ 25.48 Natural Gas per Mcf.... $ 1.30 $ 1.51 $ 2.04 $ 2.03 $ 1.99 $ 1.76 $ 2.80

- -------- (a) Estimated based on qualifying sales volumes through June 30, 2000 and the factors used in the calculation of the 1999 Section 29 tax credit. The actual 2000 Section 29 credit will be determined in February 2001. 8 Historical Trust Distributions and Related Data Trust units were initially sold to the public at $10.00 per unit in February 1992. Annual cash distributions paid, Section 29 federal income tax credits available per trust unit, cost depletion factor (the percentage of trust unit cost allowed as a cost depletion deduction for federal income tax purposes), and the total present value (discounted at 10%) of estimated future net revenues at December 31 of each year were as follows:

Total Present Section 29 Value of Tax Credits Estimated Cash Per Cost Future Net Distributions Trust Depletion Revenues per Trust Unit Unit Factor at December 31 -------------- ----------- --------- -------------- 1992.................... $ 1.217402 $0.092 7.0% $54,589,000 1993.................... 1.282923 0.150 7.0 40,911,000 1994.................... 1.124811 0.203 8.5 41,241,000 1995.................... 0.929705 0.180 8.1 42,243,000 1996.................... 1.346162 0.189 9.5 76,847,000 1997.................... 1.734541 0.212 8.8 43,496,000 1998.................... 1.154555 0.162 8.0 35,776,000 1999.................... 1.091635 0.158 8.9 60,626,000 2000 (through September)............. 1.345293 0.082(a) 7.7 -- ---------- ------ $11.227027 $1.428 ========== ======

- -------- (a) Estimated based on qualifying sales volumes attributable to distributions through August 2000 and the factors used in the calculation of the 1999 Section 29 credit. The actual 2000 Section 29 credit will be determined in February 2001. Posted West Texas Intermediate oil prices and wellhead gas prices used in calculating the estimated future net revenues were:

December 31, Oil Natural Gas - ------------ ------ ----------- 1992......................................................... $18.00 $1.69 1993......................................................... 12.50 1.75 1994......................................................... 16.00 1.51 1995......................................................... 18.00 1.37 1996......................................................... 24.25 2.64 1997......................................................... 15.50 1.76 1998......................................................... 9.50 1.88 1999......................................................... 22.75 2.19

9 The Offering Trust units offered by Cross Timbers Oil...................... 1,200,000 Trust units outstanding.......... 6,000,000 Cross Timbers Oil ownership after the offering............... 160,000 trust units if the underwriters do not exercise their over-allotment option; none if they exercise their option in full. Use of proceeds.................. Cross Timbers Oil will receive all net proceeds from this offering, which will be used to repay indebtedness under its revolving credit facility. NYSE symbol...................... CRT Investing in the Trust Units Investing in these trust units differs from investing in corporate stock in the following ways: . trust unitholders are owed a fiduciary duty by the trustee, but not by Cross Timbers Oil; . trust unitholders have limited voting rights; . trust unitholders are taxed directly on their proportionate share of trust net income; . trust unitholders are entitled to federal income tax depletion and trust administrative expense deductions; . substantially all trust income must be distributed to trust unitholders; and . trust assets are limited to the net profits interests which have a finite economic life. 10 RISK FACTORS Trust Distributions Will Be Sensitive to Changing Oil and Natural Gas Prices 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 Cross Timbers Oil. These factors include, among others: . political conditions in the Middle East; . worldwide economic conditions; . weather conditions; . the supply and price of foreign oil and natural gas; . the level of 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. Trust Distributions Are Affected by Production and Development Costs for the 75% Net Profits Interests Properties Production and development costs on the 75% net profits interests properties are deducted in the calculation of the trust's share of net proceeds. Accordingly, higher or lower production and development costs, without concurrent increases in revenues, will directly decrease or increase the amount received by the trust for its net profits interests. For a summary of these costs for the last three and one-half years, see "The Underlying Properties-- Historical Results from the Underlying Properties." If development and production costs of the 75% net profits interests properties located in a particular state exceed the proceeds of production 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. The 75% net profits interests properties include all of Cross Timbers Oil's working interests in seven producing properties located in Texas and Oklahoma. Each of these properties has been unitized for the purpose of conducting secondary recovery operations to increase or maintain production levels. Under the terms of the agreements establishing the units, if the requisite percentage of working interest owners in the unit approves a development project, all such owners are required to pay their proportionate share of development costs. The working interests owned by Cross Timbers Oil do not constitute a sufficient interest in any of the units to veto or control a development decision. Under the terms of the conveyances creating the 75% net profits interests, the trust will not be liable for any development costs, but the amount of development costs will be deducted when computing net proceeds payable to the trust. The net proceeds payable to the trust for production from the underlying properties will be reduced by all related development costs, and, if materially increased development activities were to 11 occur, distributions from the trust could be materially and adversely affected. If these development costs and production expenses exceed the proceeds of production from the properties, the trust would not receive payments from the properties until the proceeds from production exceed the cumulative excess of costs and expenses plus accrued interest during the deficit period. The computation of net proceeds is made separately for each conveyance creating the 75% net profits interests from working interest properties in Texas and Oklahoma. Any excess development costs and production expenses on working interest properties in one state will not reduce the net proceeds payable from working interest properties in the other state. For example, as a result of low oil prices and a development project to convert one of the Texas properties underlying the 75% net profits interests to carbon dioxide injection, costs exceeded revenues by a total of $832,330 for the period from April 1998 through April 1999 and in August 1999. These excess costs and related accrued interest were recovered from May 1999 through May 2000. After two years of excess cost recoveries, the Texas 75% net profits interests began contributing to trust royalty income in May 2000. Primarily because of lower oil prices and reduced production resulting from mechanical complications on one of the underlying properties, costs also exceeded revenues for five monthly net proceeds calculations for the Oklahoma 75% net profits interests from August 1998 through September 1999. These costs were recovered from October 1998 through October 1999. Excess development costs occurred twice prior to 1998. Development costs and production expenses exceeded the proceeds of production from the working interest properties in Texas from January to April 1994; these excess costs were recovered from May to August 1994. Development costs and production expenses exceeded the proceeds of production from the working interest properties in Oklahoma from October 1993 to June 1994; these excess costs were recovered from July to September 1994. Trust Reserve Estimates Are Uncertain The value of the trust units will depend upon, among other things, the reserves attributable to the trust's net profits interests. Estimating reserves is inherently uncertain. Ultimately, actual production, revenues and expenditures for the underlying properties will vary from estimates and those variations could be material. Petroleum engineers consider many factors and make assumptions in estimating reserves. Those factors and assumptions include: . historical production from the area compared with production rates from similar producing areas; . the assumed effect of governmental regulation; and . assumptions about future commodity prices, production and development costs, severance and excise taxes, and capital expenditures. Changes in these assumptions can materially change reserve estimates. The trust's reserve quantities and revenues are based on estimates of reserves and revenues for the underlying properties. The method of allocating a portion of those reserves to the trust is complicated because the trust holds an interest in net profits and does not own a specific percentage of the oil and natural gas reserves. See "The Underlying Properties--Oil and Natural Gas Reserves" for a discussion of the method of allocating proved reserves to the trust. Production Risks Can Adversely Affect Trust Distributions The occurrence of drilling, production or transportation accidents at any of the underlying properties will reduce trust distributions by the amount of uninsured costs. These accidents may result in personal injuries, property damage, damage to productive formations or equipment and environmental damages. Any uninsured costs would be deducted as a production cost in calculating net proceeds payable to the trust. 12 Neither the Trust Nor Cross Timbers Oil Controls Operations and Development Neither the trustee nor the trust unitholders can influence or control the operation or future development of the underlying properties. Because Cross Timbers Oil does not operate most of the underlying properties, it is unable to significantly influence the operations or future development of the underlying properties. 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. Cross Timbers Oil May Transfer or Abandon Underlying Properties Although it has no current intention of selling any of the underlying properties, Cross Timbers Oil may at any time transfer all or part of the underlying properties. You will not be entitled to vote on any transfer, and the trust will not receive any proceeds of the transfer. Following any transfer, the underlying properties will continue to be subject to the net profits interests of the trust, but the net proceeds from the transferred property would be calculated separately and paid by the transferee. The transferee would be responsible for all of Cross Timbers Oil's obligations relating to calculating, reporting and paying to the trust net profits on that portion of the underlying properties, and Cross Timbers Oil would have no continuing obligation to the trust for those properties. The operator, Cross Timbers Oil or any transferee may abandon any well or property if it reasonably believes that the well or property can no longer produce in commercially economic quantities. This could result in termination of the net profits interest relating to the abandoned well. Net Profits Interests Can Be Sold or the Trust May Be Terminated The trustee must 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 trustee must also sell the net profits interests if the annual gross proceeds from the underlying properties are less than $1 million for each of two consecutive years. Sale of all the net profits interests will terminate the trust. The net proceeds of any sale will be distributed to the trust unitholders. Trust Unitholders Will Have Limited Voting Rights Your voting rights as 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. Trust Unitholders Will Have Limited Ability to Enforce Rights The trust indenture and related trust law permit the trustee and the trust to sue Cross Timbers Oil or any other future owner of the underlying properties to compel it 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, your recourse as a trust unitholder would likely be limited to bringing a lawsuit against the trustee to compel the trustee to take specified actions. You probably would not be able to sue Cross Timbers Oil or any future owner of the underlying properties. Limited Liability of Trust Unitholders Is Uncertain Texas law is not clear whether a trust unitholder could be held personally liable for the trust's liabilities if those liabilities exceeded the value of the trust's assets. Cross Timbers Oil believes it is highly unlikely the trust could incur such excess liabilities. As a royalty interest, the trust's net profit interest is generally not subject to operational and environmental 13 liabilities and obligations. The trust conducts no active business that would give rise to other business liabilities. The trustee has limited ability to incur obligations on behalf of the trust. The trustee must ensure that all contractual liabilities of the trust are limited to claims against the assets of the trust. The trustee will be liable for its failure to do so. Cross Timbers Oil's Liability to the Trust Is Limited The net profits interest conveyances provide that Cross Timbers Oil will not be liable to the trust for performing its duties in operating the underlying properties as long as it acts in good faith. Trust Assets Are Depleting Assets The net proceeds payable to the trust are derived from the sale of depleting assets. Accordingly, the portion of the distributions to trust unitholders attributable to depletion may be considered a return of capital. 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 operators 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 Cross Timbers Oil. For federal income tax purposes, depletion is reflected as a deduction, which is anticipated to be $ per trust unit in 2000, based on a trust unit purchase price of $ . See "Federal Income Tax Consequences--Royalty Income and Depletion." An IRS Ruling Has Not Been Requested The trust has received an opinion of tax counsel that the trust is a "grantor trust" for federal income tax purposes. This means that: . you will be taxed directly on your pro rata share of the net income of the trust, regardless of whether all of that net income is distributed to you; . you will be allowed depletion deductions equal to the greater of percentage depletion or cost depletion, computed on the tax basis of your trust units, and your pro rata share of other deductions of the trust; and . you will be allowed the tax credit of your share of qualifying coal seam gas production provided under Section 29 of the Internal Revenue Code, subject to limitations described in this prospectus. Tax counsel believes that its opinion is in agreement with the present position of the IRS regarding grantor trusts. Neither Cross Timbers Oil nor the trustee has requested a ruling from the IRS regarding these tax questions. There can be no assurances that Cross Timbers Oil or the trust would be granted such a ruling if requested or that the IRS will not change its position in the future. The tax treatment of the trust and trust unitholders could be different from that described above if the IRS were to successfully challenge that treatment. See "Federal Income Tax Consequences." 14 FORWARD-LOOKING STATEMENTS Some statements made by Cross Timbers Oil in this prospectus are prospective and constitute forward-looking statements. These forward-looking statements involve known and unknown risks, uncertainties and other factors that could cause actual results to differ materially from future results expressed or implied by the forward-looking statements. The most significant risks, uncertainties and other factors are discussed under "Risk Factors" above. USE OF PROCEEDS The trust will not receive any proceeds from the sale of the trust units. Cross Timbers Oil will receive all proceeds from the sale of trust units after deducting underwriting discounts and costs of the offering paid by Cross Timbers Oil. The net proceeds will be approximately $ million and will increase to $ million if the underwriters exercise their over-allotment option in full. Cross Timbers Oil intends to apply the net proceeds from the offering to repay outstanding indebtedness under its bank revolving credit facility. The facility bears interest at a floating rate, currently 8.4%, and matures on May 12, 2005. Cross Timbers Oil incurred its bank debt to finance acquisitions of oil and natural gas producing properties, repurchases of Cross Timbers Oil common stock, and development expenditures. PRICE RANGE OF TRUST UNITS AND DISTRIBUTIONS The trust units are traded on the NYSE under the symbol "CRT." The following table sets forth, for the periods indicated, the high and low prices of the trust units as reported on the New York Stock Exchange Composite Tape and the amount of distributions per trust unit.

Sales Price Cash --------------- Distributions Low High per Trust Unit ------- ------- -------------- 1997: First Quarter............................... $13.625 $15.750 $.511589 Second Quarter.............................. 14.250 16.750 .536106 Third Quarter............................... 16.000 17.750 .353022 Fourth Quarter.............................. 16.000 18.500 .333824 1998: First Quarter............................... $13.563 $17.250 $.382494 Second Quarter.............................. 13.500 17.688 .267899 Third Quarter............................... 11.063 14.250 .272882 Fourth Quarter.............................. 7.625 12.688 .231280 1999: First Quarter............................... $ 8.438 $10.125 $.240065 Second Quarter.............................. 9.000 10.750 .195230 Third Quarter............................... 10.125 13.875 .276342 Fourth Quarter.............................. 9.250 12.750 .379998 2000: First Quarter............................... $ 9.500 $14.750 $.383466 Second Quarter.............................. 10.000 14.375 .404105 Third Quarter .............................. 13.000 17.000 .557722 Fourth Quarter (through October 4).......... 15.063 16.188 --

The closing price of the trust units on the NYSE on October 4, 2000, was $15.69. As of October 4, 2000, there were 6,000,000 trust units outstanding and approximately 162 trust unitholders of record. 15 CROSS TIMBERS OIL COMPANY Cross Timbers Oil is a leading United States independent energy company. It engages in the acquisition, development and exploration of oil and natural gas properties, and in the production, processing, marketing and transportation of oil and natural gas in the United States. Cross Timbers Oil organized the trust and conveyed the net profits interests to the trust in 1991 in exchange for all of the trust units. Cross Timbers Oil continues to own the underlying properties from which the net profits interests were conveyed. Cross Timbers Oil purchased a total of 1,360,000 trust units during the period from July 1996 to January 1998 for an average price of $13.75 per unit. Management of Cross Timbers Oil has been involved in the formation of three other publicly traded royalty trusts. The trusts are the Hugoton Royalty Trust formed in 1998, and the Permian Basin Royalty Trust and the San Juan Basin Royalty Trust both formed in 1980. Cross Timbers Oil may form additional trusts with other properties. THE TRUST The trust was created under the laws of the State of Texas in 1991. In connection with the formation of the trust, Cross Timbers Oil conveyed to the trust the net profits interests in the underlying properties in exchange for all 6,000,000 of the trust units. The trustee is Bank of America, N.A. The trustee can authorize the trust to borrow money to pay trust administrative or incidental expenses that exceed cash held by the trust. The trustee may authorize the trust to borrow from the trustee as a lender. Because the trustee is a fiduciary, the terms of the loan must be fair to the trust unitholders. The trustee may also deposit funds awaiting distribution in an account with itself, if the interest paid to the trust at least equals amounts paid by the trustee on similar deposits. The trust pays the trustee a fee of less than $10,000 per year. The trust will also incur legal, accounting and engineering fees, printing costs and other expenses that are deducted from the net proceeds received by the trust before distributions are made to trust unitholders. These costs and expenses totaled $152,000 for the year ended December 31, 1999. THE UNDERLYING PROPERTIES Cross Timbers Oil owns the underlying properties, subject to the net profits interests conveyed to the trust. Cross Timbers Oil may, at any time, sell all or any portion of the underlying properties, subject to the net profits interests. It has no current intention to do so. The underlying properties include Cross Timbers Oil's undivided interests in specified oil and natural gas leases and the production from existing and future wells on those leases. Cross Timbers Oil's interests cover the leased acreage and wells drilled on that acreage. Any production resulting from additional wells drilled on the underlying properties, or any deepening or opening of new producing zones in existing wells, will be attributable to the underlying properties. Accordingly, those activities, if successful, will increase or replace production from the underlying properties and increase or maintain revenues subject to the trust's net profits interest. Cross Timbers Oil's interests comprising the underlying properties are referred to in the oil and natural gas industry as an "overriding royalty", "royalty" and a "working interest." A working interest is an interest of an oil and natural gas lease entitling its owner to receive a specified percentage of production, but requiring the owner to bear the cost of exploring for, developing and producing oil and natural gas from the property. Overriding royalty and royalty interests are interests in oil and gas 16 properties entitling the owner to receive a specified percentage of production, with no requirement for the owner to bear the cost of exploration, development or production. Where the working interest is held by a number of persons on a single lease, a working interest owner is designated the lease operator by agreement. Major oil companies and large independent producers operate most of the underlying properties. A lease operator has significant influence on operations of the lease, including the timing and amount of discretionary expenditures for operational and development activities. Historical Results from the Underlying Properties The following table provides oil and natural gas sales volumes, average sales prices, revenues, direct operating expenses and development costs relating to the underlying properties for 1997, 1998 and 1999 and the six-month periods ended June 30, 1999 and 2000.

Six Months Ended June 30 Year Ended December 31 (Unaudited) ------------------------- ------------------ 1997 1998 1999 1999 2000 -------- ------- ------- -------- -------- (in thousands, except per unit data) Computation of Royalty Income 90% Net Profits Interests Revenues Oil sales.............. $ 1,853 $ 1,412 $ 1,347 $ 550 $ 1,094 Natural gas sales...... 8,798 6,955 7,133 3,008 4,270 -------- ------- ------- -------- -------- Total................. 10,651 8,367 8,480 3,558 5,364 -------- ------- ------- -------- -------- Costs--Taxes, transportation and other ................ 967 849 1,444 569 879 -------- ------- ------- -------- -------- Net proceeds.......... 9,684 7,518 7,036 2,989 4,485 -------- ------- ------- -------- -------- Royalty Income--90% net profits interests..... 8,716 6,766 6,332 2,690 4,036 -------- ------- ------- -------- -------- 75% Net Profits Interests Revenues Oil sales.............. 6,289 3,844 3,842 1,436 3,224 Natural gas sales...... 226 139 127 43 118 -------- ------- ------- -------- -------- Total................. 6,515 3,983 3,969 1,479 3,342 -------- ------- ------- -------- -------- Costs Taxes, transportation and other............. 556 347 165 61 311 Production and other expenses.............. 2,645 2,580 2,388 1,195 1,241 Development costs...... 869 1,143 736 441 348 Excess costs........... -- (515) (433) (363) -- Recovery of excess costs and accrued interest.............. -- 10 634 141 384 -------- ------- ------- -------- -------- Total................. 4,070 3,565 3,490 1,475 2,284 -------- ------- ------- -------- -------- Net proceeds.......... 2,445 418 479 4 1,058 -------- ------- ------- -------- -------- Royalty Income--75% net profits interests..... 1,834 314 359 3 794 -------- ------- ------- -------- -------- Total Royalty Income.. $ 10,550 $ 7,080 $ 6,691 $ 2,693 $ 4,830 ======== ======= ======= ======== ======== Underlying Properties Oil and Gas Sales Volumes Oil sales (Bbls)....... 424 392 349 175 169 Natural gas sales (Mcf)................. 4,419 3,502 3,643 1,735 1,567 Total sales in Mcfe.... 6,963 5,854 5,737 2,785 2,581 Average Prices Oil per Bbl............ $ 19.20 $ 13.40 $ 14.88 $ 11.36 $ 25.48 Natural gas per Mcf.... $ 2.04 $ 2.03 $ 1.99 $ 1.76 $ 2.80

Discussion and Analysis of Historical Results from the Underlying Properties Years Ended December 31, 1997, 1998 and 1999 Royalty income for 1997 was $10,550,000 as compared with $7,080,000 for 1998 and $6,691,000 for 1999. The 33% decrease in royalty income from 1997 to 1998 was primarily because of lower oil prices and lower gas volumes related to lawsuit settlement proceeds of $733,000 17 received in 1997. The 5% decrease in royalty income from 1998 to 1999 was primarily because of recovery of prior year excess costs. Royalty income derived from gas sales was 69% in 1997, 80% in 1998 and 79% in 1999. Royalty income is recorded when received by the trust, which is the month following receipt by Cross Timbers Oil, and generally two months after oil production and three months after gas production. Royalty income is generally affected by three major factors: (1) oil and gas sales volumes; (2) oil and gas sales prices; and (3) costs deducted in the calculation of royalty income. Sales Volumes. Underlying oil sales volumes decreased 7% from 1997 to 1998, as compared to a 11% decrease from 1998 to 1999. The decline in oil volumes from 1997 to 1998 was the result of a temporary disruption of production resulting from mechanical complications on one of the underlying Oklahoma working interest properties, as well as the initial downtime of development projects on some of the properties underlying the 75% net profits interests. Approximately half the 1999 decline was attributable to the same mechanical complications that affected 1998 volumes. Production on this property gradually increased over the last half of 1999. The unit operator is planning a well workover program in 2000 to increase production levels after pumping unit mechanical problems in the last half of 1998 forced many wells to be shut-in because oil prices were too low to support costly repairs. The remainder of the 1999 decline in oil volumes primarily reflected natural production decline. Underlying gas sales volumes decreased 21% from 1997 to 1998, as compared to a 4% increase from 1998 to 1999. Underlying gas sales volumes for 1997 included 636,000 Mcf attributable to lawsuit settlement proceeds received by the trust. Excluding the effects of volumes related to lawsuit settlement proceeds, gas sales volumes declined 7% from 1997 to 1998 primarily because of natural decline and timing of cash receipts. Increased volumes from 1998 to 1999 were primarily attributable to significant receipts related to prior periods. Sales Prices. The average oil price for 1997 was $19.20 per Bbl, 43% higher than the 1998 average oil price of $13.40, which was 10% lower than the 1999 average price of $14.88. Because of the two-month interval between oil production and receipt by the trust of related royalty income, the 1998 average price includes the effect of oil prices that began to weaken in December 1997 and continued to decline through 1998. West Texas Intermediate posted crude oil prices dropped to $8.00 per barrel in December 1998, the lowest level since 1978. After OPEC members and other oil producers agreed to production cuts in March 1999, oil prices climbed throughout the year. The posted price reached $24.00 in December 1999, the highest level at that time since the 1990 Persian Gulf War. The 1997 average gas price was $2.04 per Mcf, relatively unchanged from the 1998 average gas price of $2.03, which was 2% higher than the 1999 average price of $1.99. Prior to 1999, purchaser deductions were netted in the gas price. As of 1999, these purchaser deductions are included in taxes, transportation and other costs (see "Costs" below). Considering the effect of this change in classification, gas prices declined 16% from 1998 to 1999. Gas prices were lower in 1999 primarily because of the abnormally warm winter of 1998-1999 across the United States that resulted in higher levels of gas in storage. San Juan Basin gas prices, in particular, were lower in 1999 because of an abundance of hydroelectric energy in West Coast markets following a winter with abnormally high precipitation. Gas prices trended higher during 1999 as gas in storage declined. San Juan Basin gas prices have strengthened relative to prices in other regions because of increased demand in the southwest U.S., including increased use of gas during the summer to 18 generate electricity. Also, recently completed pipelines have redirected a portion of western Canadian gas supplies from West Coast to East Coast markets, alleviating some downward price pressure for gas sold in California. Costs. Because properties underlying the 90% net profits interests are royalty and overriding royalty interests, the calculation of royalty 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 royalty income from the 75% net profits interests includes deductions for production and development costs since the related underlying properties are working interests. Royalty 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 cannot reduce royalty income from other conveyances, but must be recovered, with accrued interest, from future net proceeds of that conveyance. Before adjustment for excess costs (see "Excess Costs" below), total costs deducted in the calculation of royalty income were $5,037,000 in 1997, $4,919,000 in 1998 and $4,733,000 in 1999. The 2% decrease in costs from 1997 to 1998 is primarily the result of lower production taxes associated with lower oil and gas revenues, largely offset by increased development costs. Higher 1998 development costs were primarily associated with a carbon dioxide injection project on one of the properties underlying the Texas 75% net profits interests. The 4% decrease in costs from 1998 to 1999 is primarily attributable to decreased development costs and production expense, offset by increased purchaser deductions for gathering and compression charges (included in taxes, transportation and other) which had been netted in the gas sales price prior to 1999. Excess Costs. During 1998, costs exceeded revenues for the Texas 75% net profits interests by $505,000 and the Oklahoma 75% net profits interests by $10,000. During 1999, costs exceeded revenues for properties underlying the Texas 75% net profits interests by $327,000 and the Oklahoma 75% net profits interests by $106,000. Excess costs for the Texas 75% net profits interests were primarily the result of low oil prices and increased development costs related to the 1998 carbon dioxide injection project, while excess costs for the Oklahoma 75% net profits interests were primarily related to low oil prices and reduced oil sales volumes related to mechanical complications on one of the underlying properties. Excess costs from one conveyance cannot reduce royalty income computed under another conveyance, but must be recovered from future net proceeds of the same conveyance before the conveyance can again contribute to trust royalty income. With improved oil prices in the last half of 1999, excess costs of $527,000 were recovered for the Texas 75% net profits interests and excess costs and accrued interest of $107,000 were recovered for the Oklahoma 75% net profits interests. Excess costs and accrued interest from the Oklahoma 75% net profits interests were fully recovered in October 1999. Remaining excess costs and accrued interest were $376,000 ($282,000 net to the trust) as of December 31, 1999. Excess costs were fully recovered in May 2000. The Texas 75% net profits interests did not contribute to 1999 royalty income and only contributed $0.02 per unit to 1998 royalty income as compared to $0.18 per unit to 1997 royalty income, or 10% of total 1997 distributions. Six Months Ended June 30, 1999 and 2000 For the six months ended June 30, 1999, royalty income was $2,693,000 compared with $4,830,000 for the same 2000 period. This 79% increase in royalty income is because of higher oil and gas prices. The following are explanations of significant variances from the first six months of 1999 to the comparable period in 2000: 19 Sales Volumes. Decreased oil sales volumes in the six months ended June 30, 2000 are primarily because of the timing of cash receipts. Natural production decline was largely offset by increased production on one of the Texas working interest properties as a result of carbon dioxide injections. Decreased gas volumes are primarily because of higher natural decline in coal seam gas production and the timing of cash receipts, partially offset by purchaser volume adjustments. Sales Prices. Lower average 1999 prices reflect abnormally low prices resulting from global excess supply. After OPEC members and other oil producers agreed to production cuts in March 1999, oil prices climbed through the remainder of 1999 and first quarter 2000. Increased demand in 2000 has more than offset OPEC production increases in March and June, sustaining higher prices through June 2000. The average West Texas Intermediate posted price for June 2000 was $28.79 per Bbl. Although OPEC members have proposed additional production increases to reduce prices, during September 2000 crude oil prices rose to their highest level in the last 10 years. The average gas price increased 59%, which is partly attributable to purchaser deductions which were netted in the gas price prior to second quarter 1999. Since then, these purchaser deductions are included in taxes, transportation and other costs (see "Costs" below). Excluding the effect of this change, gas prices increased 48% over this period. Gas prices were lower in 1999 primarily because of the abnormally warm winter of 1998-1999 experienced across the United States that resulted in higher levels of gas in storage. Gas prices began to increase in May 1999 and, after declining briefly at year end, have continued to strengthen in 2000, as gas storage remains lower than prior year levels. At September 5, 2000, the average NYMEX price for the following twelve months was $4.49 per MMBtu. The trust's recent gas prices have averaged $0.40 per MMBtu higher than the NYMEX price, primarily because of the effect of higher natural gas liquids prices. Costs. Taxes, transportation and other increased primarily as a result of increased taxes on higher oil and gas revenues. Also, beginning in second quarter 1999, this cost category has included purchaser deductions for gathering and compression charges. Prior to second quarter 1999, these charges were netted in the gas sales price. As a result, taxes, transportation and other includes an increase of $286,000 in purchaser deductions. Lower development costs reflect completion of the carbon dioxide injection project on one of the underlying Texas working interest properties in third quarter 1999. Primarily because of higher oil prices, all excess costs and accrued interest for the Texas 75% net profits interests were fully recovered in second quarter 2000. After two years of excess costs and recovery of these costs, the Texas 75% net profits interests again began contributing to trust royalty income in May 2000. There are no excess costs remaining to be recovered as of June 30, 2000. Excess costs occurred in the 1999 periods because of low oil prices and costs related to the carbon dioxide injection project. Producing Acres and Well Counts For the following data, "gross" refers to the total wells or acres in which Cross Timbers Oil owns a working interest and "net" refers to gross wells or acres multiplied by the percentage working interest owned by Cross Timbers Oil. Although many wells produce both oil and natural gas, a well is categorized as an oil well or a natural gas well based upon the ratio of oil to natural gas production. The underlying royalties contain approximately 462,000 gross (approximately 26,000 net) producing acres. Information regarding the number of wells on royalty properties is generally not made available to royalty interest owners. Accordingly, an accurate well count for all underlying royalties cannot be provided. 20 The underlying working interest properties are developed properties undergoing secondary or tertiary recovery operations. The underlying working interest properties consist of 60,154 gross (2,290 net) producing acres. As of December 31, 1999, there were 1,480 gross (66.5 net) productive oil wells, 989 gross (41.6 net) injection wells and no wells in process of drilling on these properties. During 1997, 15 gross (1.5 net) producing wells were drilled. No wells were drilled during 1998. During 1999, 8 gross (0.1 net) producing wells were drilled. Non-Producing Acres 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. Cross Timbers Oil is the owner of underlying mineral interests in the majority of this acreage. The trust is entitled to 10% of oil and gas production attributable to the underlying mineral properties, 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. Oil and Natural Gas Sales Prices and Production Costs The following table shows the average sales prices per Bbl of oil and Mcf of natural gas produced and the production costs, production and property taxes and transportation costs per Mcfe for the underlying properties:

Six Months Ended Year Ended December 31 June 30 ----------------------- ----------------- 1997 1998 1999 1999 2000 ------- ------- ------- -------- -------- Sales prices: Oil (per Bbl)................... $ 19.20 $ 13.40 $ 14.88 $ 11.36 $ 25.48 Natural gas (per Mcf)........... 2.04 2.03 1.99 1.76 2.80 Production costs (per Mcfe)...... 0.38 0.44 0.42 0.43 0.48 Production and property taxes and transportation costs (per Mcfe)........................... 0.22 0.20 0.28 0.23 0.46

Producing Acreage, Wells and Drilling 90% Net Profits Interests. These underlying properties are royalty and overriding royalty interests primarily located in mature producing oil and gas fields. The most significant producing region for these properties is located is the San Juan Basin in northwestern New Mexico. Estimated proved reserves attributable to the trust's 90% net profits interests from this region totaled 29.3 Bcf of natural gas at December 31, 1999, or approximately 82% of total gas reserves attributable to the trust's 90% net profits interests at that date. Cross Timbers Oil estimates that underlying properties in the San Juan Basin include more than 2,000 gross (approximately 30 net) wells, covering over 60,000 gross acres. Most of these wells are operated by Amoco Production Company and Burlington Resources Oil & Gas Company. Production from conventional gas wells is primarily from the Dakota, Mesaverde and Pictured Cliffs formations. Exploitation of coal seam gas reserves in the Fruitland formation was the most significant recent development activity in the San Juan Basin until the drilling period for the federal income tax credit expired on January 1, 1993. Since that date, operators in the San Juan Basin have continued to report development of coal seam gas reserves without the incentive of the federal income tax credit. Cross Timbers Oil does not know whether any of this development activity has directly affected trust royalties attributable to such reserves or production. During 1996, additional eastward pipeline capacity was completed in the San Juan Basin, reducing the dependence of San Juan Basin gas on California markets and effectively increasing San Juan Basin gas prices in relation to prices from other regions. Gas-powered electricity generation continues to increase in the southwest U.S., thereby increasing demand for San Juan Basin gas. Additional eastward pipeline capacity for western 21 Canadian gas supplies, which previously were primarily directed to U.S. West Coast markets, has also improved the market for San Juan Basin gas. The underlying properties also include royalties in the Sand Hills field of Crane County, Texas. Most of these properties are operated by Exxon Company, U.S.A. and Chevron, U.S.A. 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. 75% Net Profits Interests. The underlying properties consist of working interests, as detailed below, that are developed properties undergoing secondary or tertiary recovery operations:

Ownership by Cross Timbers Oil ----------------- Net Working Revenue Unit County/State Operator Interest Interest ---- --------------- -------- -------- -------- North Central Mobil Producing Texas and New Mexico, Inc. 3.2% 2.1% Levelland.............. Hockley/Texas North Cowden............ Ector/Texas Occidental Permian Ltd. 1.7% 1.4% Penwell................. Ector/Texas Texaco Exploration and Production, Inc. 5.2% 4.6% Sharon Ridge Canyon..... Borden/Texas Exxon Company, U.S.A. 4.3% 2.8% Hewitt.................. Carter/Oklahoma Exxon Company, U.S.A. 11.3% 9.9% South Graham Deese...... Carter/Oklahoma Maynard Oil Company 8.2% 7.0% Wildcat Jim Penn........ Carter/Oklahoma Texaco Exploration and Production, Inc. 8.6% 7.5%

Oil and Natural Gas Reserves Miller and Lents has estimated oil and gas reserves attributable to the net profits interests as of December 31, 1996, 1997, 1998 and 1999. 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. Miller and Lents estimated reserve quantities and revenues for the net profits interests from projections of reserves and revenues attributable to the combined interests of the trust and Cross Timbers Oil in the underlying properties. Since the trust owns defined net profits interests, the trust does not own a specific ownership percentage of the oil and gas reserve quantities. Accordingly, reserves allocated to the trust's 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 were 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 revenues are not subject to taxation at the trust level. Year-end oil prices used to determine the standardized measure were based on a West Texas Intermediate crude oil posted price of $24.25 per Bbl in 1996, $15.50 per Bbl in 1997, $9.50 per Bbl in 1998 and $22.75 per Bbl in 1999. The year-end weighted average gas prices used to determine the standardized measure were $2.64 per Mcf in 1996, $1.76 per Mcf in 1997, $1.88 per Mcf in 1998 and $2.19 per Mcf in 1999. 22 During 2000, Cross Timbers Oil filed estimates of oil and natural gas reserves as of December 31, 1999 with the U.S. Department of Energy on Form EIA-23. These estimates are consistent with the reserves reported in this prospectus for the underlying properties as of December 31, 1999, with the exception that Form EIA-23 includes only reserves from properties operated by Cross Timbers Oil. Proved Reserves The following table summarizes changes in estimated proved reserves attributable to the net profits interests and the underlying properties from December 31, 1996 through December 31, 1999 (in thousands):

Net Profits Interests ------------------------------------------------------------- 90% Net 75% Net Underlying Profits Interests Profits Interests Total Properties -------------------- -------------------- ----------------- ------------------ Natural Natural Natural Oil Gas Oil Gas Oil Gas Oil Gas (Bbls) (Mcf) (Bbls) (Mcf) (Bbls) (Mcf) (Bbls) (Mcf) -------- ---------- --------- --------- ------- -------- -------- -------- Balance, December 31, 1996................... 680.8 39,680.6 1,805.0 690.5 2,485.8 40,371.1 5,282.3 46,421.8 Extensions, discoveries and other additions... 107.9 270.0 -0- -0- 107.9 270.0 122.3 310.8 Revisions of prior estimates............. 25.5 1,779.7 (745.8) (301.5) (720.3) 1,478.2 (562.3) 1,761.7 Production............. (82.7) (3,844.1) (94.5) (33.4) (177.2) (3,877.5) (424.0) (4,418.9) ------- ---------- --------- -------- ------- -------- -------- -------- Balance, December 31, 1997................... 731.5 37,886.2 964.7 355.6 1,696.2 38,241.8 4,418.3 44,075.4 Extensions, discoveries and other additions... 3.6 95.7 -0- -0- 3.6 95.7 4.1 265.6 Revisions of prior estimates............. 25.3 1,482.1 (696.7) (282.4) (671.4) 1,199.7 (1,620.1) 894.5 Production............. (83.9) (3,010.8) (20.9) (7.9) (104.8) (3,018.7) (392.4) (3,502.1) ------- ---------- --------- -------- ------- -------- -------- -------- Balance, December 31, 1998................... 676.5 36,453.2 247.1 65.3 923.6 36,518.5 2,409.9 41,733.4 Extensions, discoveries and other additions... 10.5 162.2 -0- -0- 10.5 162.2 13.1 186.0 Revisions of prior estimates............. 109.9 1,462.1 1,251.8 533.4 1,361.7 1,995.5 2,385.7 2,322.0 Production............. (77.8) (3,152.7) (19.9) (10.2) (97.7) (3,162.9) (348.6) (3,643.0) ------- ---------- --------- -------- ------- -------- -------- -------- Balance, December 31, 1999................... 719.1 34,924.8 1,479.0 588.5 2,198.1 35,513.3 4,460.1 40,598.4 ======= ========== ========= ======== ======= ======== ======== ========

During 1997, 1998, and 1999, upward revisions of prior estimates of the 90% net profits interests' proved gas reserves were primarily because of lower than anticipated production declines. During 1997, proved oil reserves of the 90% net profits interests increased primarily because of development drilling on trust royalty acreage in Lea County, New Mexico. Revisions of prior estimates of the 75% net profits interests' proved reserves and the underlying properties' proved oil reserves in each of these years were primarily the result of changes in the year-end oil prices used in estimating proved reserves. 23 Proved Developed Reserves The following are estimated quantities of proved developed oil and gas reserves attributable to the net profits interests as of December 31, 1996 and each following year-end through December 31, 1999 (in thousands):

90% Net 75% Net Profits Interests Profits Interests Total ------------------- ----------------------------------- Natural Natural Natural Oil Gas Oil Gas Oil Gas (Bbls) (Mcf) (Bbls) (Mcf) (Bbls) (Mcf) -------- ---------- --------- ---------------- -------- December 31, 1996........ 676.6 37,705.7 1,701.2 675.7 2,377.8 38,381.4 ======= ========== ========= ======= ======= ======== December 31, 1997........ 727.9 35,947.4 908.6 346.8 1,636.5 36,294.2 ======= ========== ========= ======= ======= ======== December 31, 1998........ 672.8 34,514.0 206.4 60.7 879.2 34,574.7 ======= ========== ========= ======= ======= ======== December 31, 1999........ 715.7 33,036.5 1,375.0 570.3 2,090.7 33,606.8 ======= ========== ========= ======= ======= ========

Changes in proved developed reserves are explained under "Proved Reserves" above. Standardized Measure of Discounted Future Net Cash Flows from Proved Reserves of the Net Profits Interests The following are summary calculations of the standardized measure of discounted future net cash flows as of December 31, 1997, 1998 and 1999 (in thousands):

90% Net 75% Net Profits Interests Profits Interests Total --------------------------- ------------------------- --------------------------- December 31, December 31, December 31, --------------------------- ------------------------- --------------------------- 1997 1998 1999 1997 1998 1999 1997 1998 1999 -------- ------- -------- ------- ------ -------- -------- ------- -------- Future cash inflows..... $ 77,217 $77,207 $ 97,902 $14,975 $2,582 $ 36,670 $ 92,192 $79,789 $134,572 Future production taxes.................. (5,346) (5,401) (7,751) (847) (131) (2,487) (6,193) (5,532) (10,238) -------- ------- -------- ------- ------ -------- -------- ------- -------- Future net cash flows... 71,871 71,806 90,151 14,128 2,451 34,183 85,999 74,257 124,334 10% discount factor..... (36,221) (37,222) (46,573) (6,282) (1,259) (17,135) (42,503) (38,481) (63,708) -------- ------- -------- ------- ------ -------- -------- ------- -------- Standardized measure.... $ 35,650 $34,584 $ 43,578 $ 7,846 $1,192 $ 17,048 $ 43,496 $35,776 $ 60,626 ======== ======= ======== ======= ====== ======== ======== ======= ========

Changes in Standardized Measure of Discounted Future Net Cash Flows from Proved Reserves of the Net Profits Interests The following reconciles the changes during 1997, 1998 and 1999 in the standardized measure (in thousands):

90% Net 75% Net Profits Interests Profits Interests Total -------------------------- ------------------------ -------------------------- 1997 1998 1999 1997 1998 1999 1997 1998 1999 -------- ------- ------- ------- ------ ------- -------- ------- ------- Standardized measure, January 1.............. $ 54,884 $35,650 $34,584 $21,963 $7,846 $ 1,192 $ 76,847 $43,496 $35,776 Extensions, discoveries and other additions.... 1,311 155 384 -0- -0- -0- 1,311 155 384 Accretion of discount... 4,861 3,176 3,078 1,980 698 106 6,841 3,874 3,184 Revisions of prior estimates, changes in price and other........ (16,689) 2,369 11,864 (14,264) (7,038) 16,109 (30,953) (4,669) 27,973 Royalty income.......... (8,717) (6,766) (6,332) (1,833) (314) (359) (10,550) (7,080) (6,691) -------- ------- ------- ------- ------ ------- -------- ------- ------- Standardized measure, December 31............ $ 35,650 $34,584 $43,578 $ 7,846 $1,192 $17,048 $ 43,496 $35,776 $60,626 ======== ======= ======= ======= ====== ======= ======== ======= =======

24 Discounted Present Value of the Coal Seam Tax Credit The standardized measure above does not include the effects of the coal seam tax credit since the trust is not a taxable entity. The following summarizes the estimated coal seam tax credit attributable to the 90% net profits interests at December 31, 1997, 1998 and 1999. Such estimates are based on projected coal seam gas production through the year 2002 as estimated by independent engineers. The estimates are also based on the current year estimated Btu content and the coal seam tax credit of $1.05 per MMBtu at December 31, 1997 and 1998, and $1.02 per MMBtu at December 31, 1999. See "Regulation--Coal Seam Tax Credit."

December 31, -------------------- 1997 1998 1999 ------ ------ ------ (in thousands) Undiscounted........................................... $3,390 $2,780 $1,979 ====== ====== ====== Discounted present value at 10%........................ $2,784 $2,359 $1,740 ====== ====== ======

Regulation Oil and Natural Gas Regulation. Sales of crude oil, condensate and natural gas liquids are currently not regulated and are made at market prices. The availability, terms and cost of transportation significantly affect sales of natural gas. The interstate transportation and sale for resale of natural gas is subject to federal regulation, including transportation rates, storage tariffs and various other matters, primarily by the Federal Energy Regulatory Commission. Federal and state regulations govern the price and terms for access to natural gas pipeline transportation. The Federal Energy Regulatory Commission's regulations for interstate natural gas transmission in some circumstances may also affect the intrastate transportation of natural gas. While natural gas prices are currently unregulated, Congress historically has been active in the area of natural gas regulation. Cross Timbers Oil cannot 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, the proposals might have on the operations of the underlying properties. Environmental Regulation. Federal, state and local laws regulating the discharge of materials into the environment affect companies that are engaged in the oil and gas industry. Those laws may impact operations of the underlying properties. Cross Timbers Oil believes that it is in substantial compliance with the environmental laws and regulations that apply to the operations of the underlying properties. Cross Timbers Oil has not previously incurred material expenses in complying with environmental laws and regulations that affect operations of the underlying properties. It does not currently expect that future compliance will have a material adverse effect on the trust or the monthly distributions. State Regulation. The States of Texas, New Mexico and Oklahoma 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 states may regulate rates of production and may establish maximum daily production allowables from both oil and natural gas wells based on market demand or resource conservation, or both. Other Regulation. The petroleum industry is subject to compliance with various other federal, state and local regulations and laws. Some of those laws relate to occupational safety, resource conservation and equal employment opportunity. Cross Timbers Oil does not believe that compliance with these laws will have a material adverse effect upon the trust unitholders. 25 Certain Provisions Affecting San Juan Basin Royalty Interests Contracts creating or governing some of the underlying properties that are royalties and overriding royalties in the San Juan Basin contain provisions that purportedly either reduce the overriding royalty interest or convert the royalty or overriding royalty interest into a working interest when gas production falls below specified levels. Cross Timbers Oil believes these provisions were included in these contracts because of a federal regulation, that has since been repealed, limiting the amount of royalties and overriding royalties placed on federal leases in the San Juan Basin. No assurances, however, can be made regarding the effect of these provisions on the trust. Cross Timbers and other royalty interest owners filed a lawsuit, later joined by the trust in 1993, to recover revenues suspended by working interest owners based on their interpretation of these reduction or conversion provisions. The trust, Cross Timbers Oil and the other royalty owners settled this lawsuit in 1996, receiving past production due to the trust and receiving further compensation for an agreement to reduce the trust's interest in the involved properties. Coal Seam Tax Credit The trust receives royalty income from coal seam wells. Under Section 29 of the Internal Revenue Code, coal seam gas produced prior to January 1, 2003 from wells drilled after December 31, 1979 and before January 1, 1993, qualifies for the federal income tax credit for producing nonconventional fuels. This tax credit for 1999 was approximately $1.02 per MMBtu. Such credit, calculated based on the trust unitholder's pro rata share of qualifying production, may not reduce the trust unitholder's regular tax liability (after the foreign tax credit and certain other nonrefundable credits) below his alternative minimum tax. Any part of the Section 29 tax credit not allowed for the tax year solely because of this limitation is subject to certain carryover provisions. Title to Properties Cross Timbers Oil believes that its title to the underlying properties is, and the trust's title to the net profits interests will be, good and defensible in accordance with standards generally accepted in the oil and gas industry. The underlying properties are typically subject, in one degree or another, to one or more of the following: . royalties, overriding royalties and other burdens, under oil and gas leases; . contractual obligations, including, in some cases, development obligations, arising under operating agreements, farmout agreements, production sales contracts and other agreements that may affect the properties or their titles; . liens that arise in the normal course of operations, such as those for unpaid taxes, statutory liens securing unpaid suppliers and contractors and contractual liens under operating agreements; . pooling, unitization and commutation agreements, declarations and orders; and . easements, restrictions, rights-of-way and other matters that commonly affect property. To the extent that these burdens and obligations affect Cross Timbers Oil's rights to production and the value of production from the underlying properties, they have been taken into account in calculating the trust's interests and in estimating the size and the value of the reserves attributable to 26 the net profits interests. Cross Timbers Oil believes that the burdens and obligations affecting the underlying properties and the net profits interests are conventional in the industry for similar properties. Cross Timbers Oil also believes that the burdens and obligations do not in the aggregate materially interfere with the use of the underlying properties and will not materially adversely affect the value of the net profits interests. The net profits interests covering the underlying properties in Texas constitute interests in real property under Texas law. Although the matter is not entirely free from doubt, it is the opinion of Oklahoma and New Mexico counsel that the net profits interests covering the underlying properties in Oklahoma and New Mexico also constitute interests in real property under Oklahoma and New Mexico law. Cross Timbers Oil has recorded the conveyances in the appropriate real property records of Oklahoma, Texas and New Mexico. If a determination were made in a bankruptcy proceeding of Cross Timbers Oil that a net profits interest did not constitute a real property interest under applicable state law, it could be designated an executory contract. An executory contract is a term used, but not defined, in the federal bankruptcy code to refer to a contract under which the obligations of both the debtor and the other party are so unsatisfied that the failure of either to complete performance would constitute a material breach excusing performance by the other. If a net profits interest were designated an executory contract and rejected in the bankruptcy proceeding, Cross Timbers Oil would not be required to perform its obligations under the net profits interest and the trust would seek damages as one of Cross Timbers Oil's unsecured creditors. Although no assurance can be given, Cross Timbers Oil does not believe that the net profits interests should be subject to rejection in a bankruptcy proceeding as executory contracts. Marketing Most of the natural gas production from the underlying properties is from royalty or overriding royalty interests. Owners of such interests typically do not have the right to sell their production and are generally paid under the terms of the related working interest owners sales agreement. Oil and natural gas are generally sold from the underlying properties at posted and spot prices. The majority of sales from the underlying properties comprising the 75% net profits interests are to major oil and gas companies. Information about purchasers of oil and gas from underlying properties comprising the 90% net profits interests is generally not provided by operators to Cross Timbers Oil as a royalty owner, or to the trust. Litigation There is no material litigation involving the underlying properties. 27 COMPUTATION OF NET PROCEEDS The provisions governing the computation of the net proceeds are detailed and extensive. The following description of the net profits interests and the computation of net proceeds is subject to and qualified by the more detailed provisions of the conveyances of the net profits interests that are filed as exhibits to the registration statement. See "Available Information." Net Profits Interests The net profits interests are defined net profits interests carved from the underlying properties. The net profits interests entitle the trust to receive: . 90% of the net proceeds from the sale of oil and natural gas produced from the three conveyances that represent royalty and overriding royalty interests underlying properties; and . 75% of the net proceeds from the sale of oil and natural gas produced from the two conveyances that represent working interests underlying properties. The amounts paid to the trust for the net profits interests are based on the definitions of "gross proceeds" and "net proceeds" contained in the conveyances and described below. Under the conveyances, net proceeds are computed monthly. Cross Timbers Oil pays either 90% or 75% of the aggregate net proceeds attributable to a computation period to the trust on or before the last business day of the month following the computation period. Cross Timbers Oil will not pay to the trust interest on the net proceeds held by Cross Timbers Oil prior to payment to the trust. The trustee makes distributions to trust unitholders monthly. See "Description of the Trust Units--Distributions and Income Computations." Net proceeds equal the excess of gross proceeds over production costs and excess production costs attributable to a prior computation period. The 90% net profits interests are royalty and overriding royalty interests and production costs are zero. Production costs apply only to working interest properties, which comprise the 75% net profit interests. Gross proceeds means an amount received by Cross Timbers Oil from sales of oil and natural gas produced from the underlying properties, after deducting: . all general property (ad valorem), production, severance, sales, gathering, excise and other taxes except income taxes, and gathering costs; and . any payment made to the owner of an underlying property for -- natural gas not taken, but to the extent payments are allocated to natural gas taken in the future, payments are included, without interest, in gross proceeds when such natural gas is taken; -- damages, other than drainage or reservoir injury; -- rental for reservoir use; and -- payments in connection with the drilling of any well. Gross proceeds does not include consideration for the transfer or sale of any underlying property by Cross Timbers Oil or any subsequent owner to any new owner. Gross proceeds also does not include any amount for oil and natural gas lost in production or marketing or used by the owner of the underlying properties in drilling, production and plant operations. Gross proceeds includes payments for future production if they are not subject to repayment in the event of insufficient subsequent production. 28 Production costs, on a cash basis, generally means the sum of: . all payments to mineral or landowners, such as royalties or other burdens against production, delay rentals, shut-in natural gas payments, minimum royalty or other payments for drilling or deferring drilling; . any taxes paid by the owner of an underlying property, other than income taxes, to the extent not deducted or excluded in calculating gross proceeds, including estimated and accrued ad valorem and other property taxes; . costs paid by the owner of an underlying property under any joint operating agreement; . all other costs, expenses and liabilities of exploring for, drilling, operating and producing oil and natural gas, including allocated expenses such as labor, vehicle and travel costs and materials; . costs or charges associated with gathering, treating and processing natural gas; . certain interest costs; . any overhead charge; . amounts previously included in gross proceeds but subsequently paid as a refund, interest or penalty; . other costs and expenses for renewals or extensions of leases; and . at the option of the owner of an underlying property, accruals for costs approved under authorizations for expenditure. Cross Timbers Oil charges an overhead fee to administer the underlying properties. The administration includes various engineering, accounting and other administrative functions. This fee is $270,840 per year to the underlying properties and $203,130 per year net to the trust as of June 30, 2000 for all working interest underlying properties. The fee is adjusted annually and will increase or decrease each year based on changes in the year-end index of average weekly earnings of crude petroleum and natural gas workers. Excess production costs are the excess of production costs over gross proceeds, plus interest accrued at the prime rate. Therefore, if production costs exceed gross proceeds for a computation period, the trust will receive no payment for that period, and excess production costs will be carried over to the following month as a production cost in determining the excess of gross proceeds over production costs for that following month. Gross proceeds and production costs are calculated on a cash basis, except that certain costs, primarily ad valorem taxes and expenditures of a material amount, may be determined on an accrual basis. For convenience in complying with state tax laws, the net profits interests were created by five separate conveyances, one each for the three 90% net profits interests conveyances and for the two 75% net profits interests conveyances. Net proceeds are calculated separately for the underlying properties covered by each conveyance, so excess production costs in one conveyance do not reduce net proceeds from the other. Additional Provisions If a controversy arises as to the sales price of any oil or natural gas, then for purposes of determining gross proceeds: . amounts withheld or placed in escrow by a purchaser are not considered to be received by the owner of the underlying property until actually collected; 29 . amounts received by the owner of the underlying property and promptly deposited with a nonaffiliated escrow agent will not be considered to have been received until disbursed to it by the escrow agent; and . amounts received by the owner of the underlying property and not deposited with an escrow agent will be considered to have been received. The trust is not liable to the owner of the underlying properties or the operators for any production, operating, capital or other costs or liabilities attributable to the underlying properties. The trustee is not obligated to return any income received from the net profits interests. Any overpayments made to the trust due to adjustments to prior calculations of net proceeds or otherwise will reduce future amounts payable to the trust until Cross Timbers recovers the overpayments plus interest at the prime rate. The conveyances permit Cross Timbers Oil to transfer, without the consent or approval of the trust unitholders, all or any part of the underlying properties, subject to the net profits interests. The trust unitholders are not entitled to any proceeds of a transfer. Following a transfer, the underlying properties will continue to be subject to the net profits interests, and the net proceeds attributable to the transferred property will be calculated separately and paid by the transferee. As a result, any excess costs accrued and reimbursed from the transferred property prior to the transfer will not reduce the net proceeds payable to the trust from the underlying properties retained by Cross Timbers Oil. The conveyances have been recorded in the appropriate real property records to give notice of the net profits interests to Cross Timbers Oil's creditors and transferees. Cross Timbers Oil may enter into farmout, operating, participation, and other similar agreements covering an underlying property if Cross Timbers Oil believes it to be advantageous. The net profits interest held by the trust would then be calculated using the gross proceeds and production costs attributable to the interest retained by Cross Timbers Oil under the agreement and not on Cross Timbers Oil's original interest before modification by the agreement. Cross Timbers Oil may enter into any of these agreements without the consent or approval of the trustee or any trust unitholder. However, Cross Timbers Oil's interest in entering into any of these types of agreements should be parallel with that of trust unitholders because of its retained interest in 10% of the net proceeds from the conveyances of underlying properties that are royalty or overriding royalty interests and 25% of the net proceeds from the conveyances of underlying properties that are working interests. Cross Timbers Oil and any transferee will have the right to abandon any well or property if it believes the well or property ceases to produce or is not capable of producing in commercially paying quantities. Upon termination of the lease, that portion of the net profits interests relating to the abandoned property will be extinguished. Cross Timbers Oil must maintain books and records sufficient to determine the amounts payable for the net profits interests. Quarterly and annually, Cross Timbers Oil must deliver to the trustee a statement of the computation of the net proceeds for each computation period. Cross Timbers Oil will cause the annual computation of net proceeds to be audited. The audit cost will be borne by the trust. 30 FEDERAL INCOME TAX CONSEQUENCES This section summarizes all of the material federal income tax consequences of the ownership and sale of trust units. Many aspects of federal income taxation that may be relevant to a particular taxpayer or to certain types of taxpayers subject to specific tax treatment are not addressed. In addition, the tax laws can and do change regularly, and any future changes could have an adverse effect on the ownership or sale of trust units. The trust will not request advance rulings from the IRS with respect to the tax consequences of ownership or sale of trust units. Instead the trust will rely on the opinion of Winstead Sechrest & Minick P.C. regarding the classification of the trust and certain federal income tax consequences described below, which will be confirmed at the time of the closing. Winstead Sechrest & Minick P.C. believes that its opinion is in accordance with the present position of the IRS regarding grantor trusts. The tax opinion is not binding on the IRS or the courts, however, and no assurance can be given that the IRS or the courts will agree with it. The summary contained in this section is based on current provisions of the Internal Revenue Code, existing and proposed regulations, current administrative rulings and court decisions, all of which are subject to changes that may or may not be retroactively applied. Some of the applicable provisions of the Internal Revenue Code have not been interpreted by the courts or the IRS. Currently pending proposed federal tax legislation may also, under certain circumstances, have a material effect on a trust unitholder. AS A CONSEQUENCE, EACH PROSPECTIVE TRUST UNITHOLDER SHOULD CONSULT HIS OWN TAX ADVISOR REGARDING HIS PARTICULAR CIRCUMSTANCES INCLUDING, PARTICULARLY, HIS ALTERNATIVE MINIMUM TAX CIRCUMSTANCES. Summary of Legal Opinions Winstead Sechrest & Minick P.C. is of the opinion that, for federal income tax purposes: . the trust is a grantor trust and not a business entity taxable as a partnership or a corporation; and . the income from the net profits interests is royalty income subject to an allowance for depletion. Winstead Sechrest & Minick P.C. advises that, unless noted otherwise, legal conclusions stated in this section constitute its opinion. Since no ruling is being requested from the IRS with respect to the trust or trust unitholders, the IRS could challenge these opinions and statements, which do not bind the IRS or the courts. The IRS could win in court if it did challenge these matters. Classification and Taxation of the Trust In the opinion of Winstead Sechrest & Minick P.C., under current law, the trust is taxable as a grantor trust and not as a business entity. As a grantor trust, the trust is not subject to tax at the trust level. For tax purposes, the grantors, who in this case are the trust unitholders, are considered to own the trust's income and principal as though no trust were in existence. A grantor trust simply files an information return, reporting all items of income, credit or deduction which must be included in the tax returns of the trust unitholders based on their respective accounting methods and taxable years without regard to the accounting method and tax year of the trust. If, contrary to the opinion of Winstead Sechrest & Minick P.C., the trust was determined to be a business entity, it would be taxable as a partnership unless it elected to be taxed as a corporation. The principal tax 31 consequence of the trust's being treated as a partnership would be that it would report income on the accrual method of accounting on a calendar year basis and all trust unitholders would report their share of income from the trust in their tax year with which or within which the tax year of the trust ends. Direct Taxation of Trust Unitholders Since the trust is treated as a grantor trust for federal income tax purposes, each trust unitholder is taxed directly on his share of trust income and is entitled to claim his share of trust deductions. Each trust unitholder recognizes taxable income when the trust receives or accrues it, even if it is not distributed until later. Trust unitholders report their share of trust income and expenses consistent with their method of accounting and their tax year. Reporting of Trust Income and Expenses The trustee treats each royalty payment it receives as the taxable income of the trust unitholders who own trust units on the day of receipt by the trust. This will normally be the last business day of each calendar month. Similarly, the trustee pays expenses only on the day it receives a royalty payment. All expenses paid on a royalty receipt day are treated as expenses of the trust unitholders who receive the distribution of that royalty income. In most cases, therefore, the income and expenses of the trust for a period are reported as belonging to the trust unitholders who received a distribution for that period. The amount of the distribution for a trust unit generally equals the net income allocated to that trust unit, determined without regard to depletion. This correlation may not exist if, for example, the trustee were to establish a cash reserve to pay estimated future expenses or pay an expense with borrowed funds. Moreover, the IRS could attempt to impute income to those persons who were trust unitholders when a royalty payment on the net profits interests accrues. The IRS could also attempt to disallow the deduction of administrative expenses to persons who were not trust unitholders when the expenses were incurred. If the IRS were successful, trust income might be taxed to trust unitholders other than those who received the distribution relating to that income. Also, an accrual basis trust unitholder might realize royalty income in a tax year earlier than that reported by the trustee. Royalty Income and Depletion In the opinion of Winstead Sechrest & Minick P.C., the income from the net profits interests is royalty income qualifying for an allowance for depletion. The depletion allowance must be computed separately by each trust unitholder for each oil or gas property, within the meaning of Section 614 of the Internal Revenue Code. Winstead Sechrest & Minick P.C. understands that the IRS is presently taking the position that a net profits interest carved from multiple properties is a single property for depletion purposes. Accordingly, the trust takes the position that each net profits interest transferred to the trust by a conveyance within each state is a single property for depletion purposes. It will change this position if a different method were established by the IRS or the courts. The deduction for depletion is determined annually and is the greater of cost depletion or, if allowable, percentage depletion. Royalty income from production attributable to trust units owned by independent producers qualifies for percentage depletion. In general, an individual or entity with production of the equivalent of not more than 1,000 barrels of oil per day or less is an independent producer. In general, percentage depletion is a statutory allowance equal to 15% of the gross income from production from a property. Percentage depletion is subject to a net income limitation of 100% of the taxable income from the property, computed without regard to depletion deductions and specified loss carrybacks. The depletion deduction attributable to percentage depletion for a taxable year is limited to 65% of the taxpayer's taxable income for the year before allowance of independent 32 producers percentage depletion and specified loss carrybacks. Unlike cost depletion, percentage depletion is not limited to the adjusted tax basis of the property, although, like cost depletion, it reduces the adjusted tax basis, but not below zero. Cross Timbers Oil believes that trust unitholders who purchase trust units in this offering will derive a substantially greater benefit from cost depletion than from percentage depletion. In computing cost depletion for each property for any year, the allowance for the property is calculated by dividing the adjusted tax basis of the property at the beginning of the year by the estimated total number of Bbls of oil or Mcf of natural gas recoverable from the property. This amount is then multiplied by the number of Bbls of oil or Mcf of natural gas produced and sold from the property during the year. Cost depletion for a property cannot exceed the adjusted tax basis of the property. Each trust unitholder computes cost depletion using his basis in his trust units. Information is provided to each trust unitholder reflecting how his basis should be allocated among each property represented by his trust units. To the extent the depletion tax deduction exceeds cash distributions per trust unit, that excess can be deducted from the taxpayer's other sources of taxable income. Other Income and Expenses It is anticipated that the only other income of the trust will be interest income earned on funds held as a reserve or pending distribution. Other expenses of the trust include any state and local taxes imposed on the trust and administrative expenses of the trustee. Although the issue has not been finally resolved, Winstead Sechrest & Minick P.C. believes that all or substantially all of those expenses are deductible in computing adjusted gross income and, therefore, are not the type of miscellaneous itemized deductions that are allowable only to the extent that they total more than 2% of adjusted gross income. Section 29 Coal Seam Gas Tax Credit Certain of the natural gas production attributable to the net profits interests is from coal seam gas. Subject to certain statutory requirements, taxpayers are entitled to the Section 29 tax credit for production and sale of certain natural gas produced from coal seams. The Section 29 tax credit applies to coal seam gas produced and sold to unrelated party prior to January 1, 2003 from wells drilled prior to January 1, 1993 and after December 31, 1979. The Section 29 tax credit is equal to $3.00 per barrel of oil equivalent, which is 5.8 MMBtu, adjusted for inflation since 1979. The credit is reduced by a formula computation as the price of oil rises above an inflation adjusted amount. The Section 29 credit available for gas produced in 1999 was $1.02 per MMBtu. In the opinion of Winstead Sechrest & Minick P.C., if the requisite statutory requirements are met, the trust unitholders will be eligible to claim the Section 29 tax credit for sales of qualified coal seam gas production included in the calculation of the net profits interests. Cross Timbers Oil believes that all of the statutory requirements have been or will be met on substantially all of the coal seam wells. The Section 29 tax credit allowable for any taxable year cannot exceed the excess of the taxpayer's regular tax liability for that taxable year, as reduced by the taxpayer's foreign tax credits and certain nonrefundable credits, over the taxpayer's tentative minimum tax liability for that year. Any amount of Section 29 tax credit disallowed for the tax year solely because of this limitation will increase the taxpayer's minimum tax credit carryover. This credit may be carried forward indefinitely as a credit against the taxpayer's regular tax liability, subject, however to the limitation described in the first sentence of this paragraph. There is no provision for the carryback or carryforward of the Section 29 tax credit in any other circumstances, so, a trust unitholder may not receive the full benefit of the tax credit depending on his particular circumstances. 33 Alternative Minimum Tax All taxpayers are subject to an alternative minimum tax. Alternative minimum taxable income is the taxpayer's taxable income recomputed with various adjustments plus items of tax preference. In the case of persons other than independent producers, tax preferences include the excess of percentage depletion deductions for an oil or natural gas property over the adjusted tax basis of the property. Alternative minimum tax is the excess of a taxpayer's tentative minimum tax for a tax year over his regular tax for that year. Non-Passive Activity Income and Loss The income and expenses of the trust will not be taken into account in computing the passive activity losses and income under Internal Revenue Code Section 469 for a trust unitholder who acquires and holds trust units as an investment. Section 29 tax credits generated by an investment in the trust units, therefore, can be utilized to offset regular tax liability on income from any source, subject to the limitations discussed in "Section 29 Coal Seam Gas Tax Credit" above. Unrelated Business Taxable Income Certain organizations that are generally exempt from tax under Internal Revenue Code Section 501 are subject to tax on certain types of business income defined in Section 512 as unrelated business income. In the opinion of Winstead Sechrest & Minick P.C., the income of the trust will not be unrelated business taxable income so long as the trust units are not debt-financed property within the meaning of Section 514(b). In general, a trust unit would be debt-financed if the exempt organization incurs debt to acquire a trust unit or otherwise incurs or maintains a debt that would not have been incurred or maintained if the trust unit had not been acquired. Sale of Trust Units; Depletable Basis Generally, a trust unitholder will realize gain or loss on the sale or exchange of his trust units measured by the difference between the amount realized on the sale or exchange and his adjusted basis for such trust units. A trust unitholder's basis in his trust units will be equal to the amount he paid for the trust units, reduced by deductions for depletion claimed by the trust unitholder, but not below zero. Except to the extent of the depletion recapture amount explained below, gain or loss on the sale of trust units by a trust unitholder who is an individual and who is not a dealer in the trust units should be a long-term capital gain, taxable at a maximum rate of 20%, if the trust units have been held for more than 12 months. Upon the sale of the trust units, a trust unitholder will be treated as having sold his share of the net profits interests and must treat as ordinary income his depletion recapture amount, which is an amount equal to the lesser of the gain on such sale or the sum of the prior depletion deductions taken on the trust units, but not in excess of the initial basis of the trust units. The IRS could take the position that a portion of the sales proceeds is ordinary income to the extent of any accrued income at the time of the sale that was allocable to the trust units sold even though the income is not distributed to the selling trust unitholder. Taxation of Foreign Holders Unless the election described below is made, a foreign holder, consisting of a nonresident alien individual, foreign corporation, or foreign estate or trust, will be subject to federal income withholding tax on his share of gross royalty income from the net profits interests. The withholding tax will be at a 30% rate, or lower treaty rate if applicable and proper evidence is supplied to the withholding agent, applied to the gross royalty income received by the foreign holder without any deductions. Gain realized on a sale of a trust unit by a foreign holder will be subject to federal income tax only if: . the gain is otherwise effectively connected with business conducted by the foreign holder in the United States; . the foreign holder is an individual who is present in the United States for at least 183 days in the year of the sale; 34 . the foreign holder has at any time during the five-year period ending on the date of sale owned more than a 5% interest in the trust; or . the trust units cease to be regularly traded on an established securities exchange. Gain realized by a foreign holder upon the sale by the trust of all or any part of the net profits interests would be subject to federal income tax. Trust unitholders who are foreign holders may elect under Internal Revenue Code Section 871 or Section 882 or similar provisions of applicable treaties to treat income attributable to the net profits interests as effectively connected with the conduct of a trade or business in the United States. The foreign holder will then be taxed at regular federal income tax rates on the net income, rather than the gross income, attributable to the net profits interests, including gain recognized on the disposition of trust units. Absent a treaty exception, the net income of a corporate foreign holder which has made such an election will also be subject to the branch profits tax imposed under Section 884 to the extent not reinvested in a United States trade or business. To claim the deductions allowable in computing net income, including cost depletion, an electing foreign holder must file a United States income tax return. To avoid tax withholding, an electing foreign holder must provide proper certificates or other evidence to the withholding agent. Once made, the election is irrevocable unless an applicable treaty allows the election to be made annually. The election is applicable to all income and gain realized by the foreign holder on any real property interests located in the United States, including those interests held through partnerships, fixed investment trusts, and other pass-through entities. Backup Withholding In general, distributions of trust income will not be subject to backup withholding unless the trust unitholder is an individual or other noncorporate taxpayer and he fails to comply with certain reporting procedures. Tax Shelter Registration Cross Timbers Oil believes that the requirements for tax shelter registration under Internal Revenue Code Section 6111 would be met if any trust unitholder's investment base is substantially reduced by borrowing. To avoid any potential penalty, the trust has been registered as a tax shelter with the IRS. The trustee will furnish the tax shelter registration number to each trust unitholder. Each trust unitholder must disclose this number by attaching Form 8271 to his tax return. ISSUANCE OF A TAX SHELTER REGISTRATION NUMBER DOES NOT INDICATE THIS INVESTMENT OR THE CLAIMED TAX BENEFITS HAVE BEEN REVIEWED, EXAMINED OR APPROVED BY THE IRS. Reports The trustee will furnish to trust unitholders of record quarterly, and to all trust unitholders annually, reports to facilitate their computation of their tax liability. See "Description of the Trust Units--Periodic Reports." 35 STATE TAX CONSIDERATIONS The following is a brief summary of the material state income taxes and other state tax matters affecting the trust and the trust unitholders. Trust unitholders are urged to consult their own legal and tax advisors as these matters relate to their individual circumstances. Income Tax Considerations Texas presently does not have a state income tax on resident or nonresident individuals. The Texas franchise tax imposes, in effect, an income tax on corporations and limited liability companies which qualify to do business or actually do business in Texas. Trust unitholders that are corporations or limited liability companies will be subject to Texas franchise taxes on income from the net profits interests. New Mexico and Oklahoma impose income taxes upon resident and nonresidents. In the case of nonresidents, income derived from tangible property within the state is subject to tax. The income tax laws of New Mexico and Oklahoma are based on federal income tax laws. Thus, assuming the trust is taxed as a grantor trust for federal income tax purposes, the trust unitholders will be subject to New Mexico income tax on their share of income from New Mexico net profits interest and subject to Oklahoma income tax on their share of income from Oklahoma net profits interests. Nonresidents of New Mexico and Oklahoma, however, may not be taxed in those states on gains from sales of trust units. Trust unitholders may also be subject to tax by the state in which they reside on income derived from the trust. The trustee will provide information concerning the trust sufficient to identify the income of the trust allocable to each state. Trust unitholders should consult their own tax advisors to determine their income tax filing requirements with respect to their share of income of the trust allocable to states imposing an income tax on such income. Probate and Property Considerations The trust units may constitute real property or an interest in real property under the inheritance, estate and probate laws of Texas, New Mexico and Oklahoma. If the trust units are held to be real property or an interest in real property under the laws of a state in which the underlying properties are located, the trust units may be subject to devolution, probate and administrative laws, and inheritance or estate and similar taxes, under the laws of such state. 36 ERISA CONSIDERATIONS The Employee Retirement Income Security Act of 1974 regulates pension, profit-sharing and other employee benefit plans to which it applies. ERISA also contains standards for persons who are fiduciaries of those plans. In addition, the Internal Revenue Code provides similar requirements and standards which are applicable to qualified plans, which include these types of plans and to individual retirement accounts, whether or not subject to ERISA. A fiduciary of a qualified plan should carefully consider fiduciary standards under ERISA regarding the qualified plan's particular circumstances before authorizing an investment in trust units. A fiduciary should consider . whether the investment satisfies the prudence requirements of Section 404(a)(1)(B) of ERISA; . whether the investment satisfies the diversification requirements of Section 404(a)(1)(C) of ERISA; and . whether the investment is in accordance with the documents and instruments governing the qualified plan as required by Section 404(a)(1)(D) of ERISA. A fiduciary should also consider whether an investment in trust units might result in direct or indirect nonexempt prohibited transactions under Section 406 of ERISA and Internal Revenue Code Section 4975. In deciding whether an investment involves a prohibited transaction, a fiduciary must determine whether there are plan assets in the transaction. On November 13, 1986, the Department of Labor published final regulations concerning whether or not a qualified plan's assets would be deemed to include an interest in the underlying assets of an entity for purposes of the reporting, disclosure and fiduciary responsibility provisions of ERISA and analogous provisions of the Internal Revenue Code. These regulations provide that the underlying assets of an entity will not be considered "plan assets" if the equity interests in the entity are a publicly offered security. The trust units are publicly traded on the New York Stock Exchange. Fiduciaries, however, will need to determine whether the acquisition of trust units is a nonexempt prohibited transaction under the general requirements of ERISA Section 406 and Internal Revenue Code Section 4975. The prohibited transaction rules are complex, and persons involved in prohibited transactions are subject to penalties. For that reason, potential qualified plan investors should consult with their counsel to determine the consequences under ERISA and the Internal Revenue Code of their acquisition and ownership of trust units. 37 DESCRIPTION OF THE TRUST INDENTURE The following information and the information included under "Description of the Trust Units" summarize the material information contained in the trust indenture. This summary may not contain all the information that is important to you. For more detailed provisions concerning the trust, you should read the trust indenture. A copy of the trust indenture was filed as an exhibit to the registration statement. See "Available Information." Creation and Organization of the Trust; Amendments Cross Timbers Oil created the net profits interests and conveyed them to the trust in exchange for 12,000,000 trust units. The 12,000,000 units were subsequently converted to 6,000,000 outstanding units. Cross Timbers Oil organized the trust under Texas law to acquire and hold the net profits interests for the benefit of the trust unitholders under an agreement between Cross Timbers Oil and the trustee. The trustee has all the power to collect and distribute proceeds receiveable by the trust and to pay trust liabilities and expenses. Neither the trust nor the trustee has any control over or responsibility for costs relating to the operation of the underlying properties. Neither Cross Timbers Oil nor other operators of the underlying properties have any contractual commitments to the trust to conduct further drilling on or to maintain their ownership interest in any of these properties. For a description of the underlying properties and other information relating to them, see "The Underlying Properties." The beneficial interest in the trust is divided into 6,000,000 trust units. Each of the trust units represents an equal undivided portion of the trust. You will find additional information concerning the trust units in "Description of the Trust Units." Amendment of the trust indenture requires a vote of holders of 80% or more of the outstanding trust units. However, no amendment may-- . increase the power of the trustee to engage in business or investment activities; . alter the rights of the trust unitholders as among themselves; or . permit the trustee to distribute the net profits interests in kind. Assets of the Trust The assets of the trust consist of net profits interests and any cash and temporary investments being held for the payment of expenses and liabilities and for distribution to the trust unitholders. Duties and Limited Powers of the Trustee The duties of the trustee are specified in the trust indenture and by the laws of the State of Texas. The trustee's principal duties consist of: . collecting income attributable to the net profits interests; . paying expenses, charges and obligations of the trust from the trust's income and assets; . distributing distributable income to the trust unitholders; and . taking any action it deems necessary and advisable to best achieve the purposes of the trust. If a trust liability is contingent or uncertain in amount or not yet currently due and payable, the trustee may create a cash reserve to pay for the liability. If the trustee determines that the cash on 38 hand and the cash to be received is insufficient to cover the trust's liability, the trustee may borrow funds required to pay the liabilities. The trustee may borrow the funds from any person, including itself. The trustee may also mortgage the assets of the trust to secure payment of the indebtedness. If the trustee borrows funds, the trust unitholders will not receive distributions until the borrowed funds are repaid. Each month, the trustee will pay trust obligations and expenses and distribute to the trust unitholders the remaining proceeds received from the net profits interests. The cash held by the trustee as a reserve against future liabilities or for distribution at the next distribution date must be invested in: . interest bearing obligations of the United States government; . repurchase agreements secured by interest-bearing obligations of the United States government; or . bank certificates of deposit. The trust may not acquire any asset except the net profits interests, cash and temporary cash investments, and it may not engage in any investment activity except investing cash on hand. The trustee may sell the net profits interests in any of the following circumstances: . the sale does not involve a material part of the trust's assets and is in the best interests of the trust unitholders. A majority of the trust units represented at a meeting of the trust unitholders where a quorum is present must approve the sale; or . the sale constitutes a material part of the trust's assets and is in the best interests of the trust unitholders. Holders representing 80% of the outstanding trust units must approve the sale. Upon termination of the trust the trustee must sell the net profits interests. No trust unitholder approval is required. The trustee will distribute to the trust unitholders the net proceeds from any sale of the net profits interests. The trustee may require any trust unitholder to dispose of his trust units if an administrative or judicial proceeding seeks to cancel or forfeit any of the property in which the trust holds an interest because of the nationality or any other status of that trust unitholder. If a trust unitholder fails to dispose of his trust units, the trustee must purchase for cash from trust assets the trust units held by the ineligible holder. The purchase price for the trust units will be the market price on a specified day. The trustee may then either cancel the trust certificate for the trust units so purchased or sell them to an eligible third party with the proceeds becoming revenue of the trust. The trustee may agree to modifications of the terms of the conveyances or to settle disputes involving the conveyances. The trustee may not agree to modifications or settle disputes involving the royalty part of the conveyances if these actions would change the character of the net profits interests in such a way that the net profits interests become working interests or that the trust becomes an operating business. Liabilities of the Trust Because the trust does not conduct an active business and the trustee has little power to incur obligations, the trust has only incurred liabilities for routine administrative expenses, such as the trustee's fees and accounting, engineering, legal and other professional fees. Cross Timbers Oil does not expect the trust to incur other types of liabilities in the future. 39 Responsibility and Liability of the Trustee The trustee is a fiduciary for the trust unitholders and is required to act in the best interests of the trust unitholders at all times. The trustee must exercise the same judgment and care in supervising and managing the trust's assets as persons of ordinary prudence, discretion and intelligence would exercise. Under Texas law, the trustee's duties to the trust unitholders are similar to the duty of care owed by a corporate director to the corporation and its shareholders. The primary difference between the trustee's duties and a corporate director's duties is the absence of the legal presumption protecting the trustee's decisions from challenge. The trustee does not make business decisions affecting the assets of the trust. Therefore, substantially all of the trustee's functions under the trust indenture are ministerial in nature. See "--Duties and Limited Powers of the Trustee," above. The trust indenture provides that the trustee may: . charge for its services as trustee; . retain funds to pay for future expenses and deposit them in its own account in compliance with applicable law; . lend funds at commercial rates to the trust to pay the trust's expenses; and . seek reimbursement from the trust for its out-of-pocket expenses. In discharging its duties to trust unitholders, the trustee may act in its discretion and will be liable to the trust unitholders only for fraud, gross negligence or acts or omissions in bad faith. The trustee will not be liable for any act or omission of its agents or employees unless the trustee acted in bad faith or with gross negligence in their selection and retention. The trustee will be indemnified for any liability or cost that it incurs in the administration of the trust, except in cases of fraud or acts or omissions in bad faith. The trustee has a lien on the assets of the trust as security for this indemnification and compensation earned as trustee. The trustee is entitled to indemnification from trust assets. Trust unitholders will not be liable to the trustee for any indemnification. See "Description of the Trust Units--Liability of Trust Unitholders." The trustee must ensure that all contractual liabilities of the trust are limited to the assets of the trust and will be liable for such contractual liabilities if it fails to do so. Under Texas law, if the trustee acts in bad faith or with gross negligence, the trustee will be liable to the trust unitholders for damages. Texas law also permits the trust unitholders to file actions seeking other remedies, including: . removal of the trustee; . specific performance; . appointment of a receiver; . an accounting by the trustee to trust unitholders; and . punitive damages. Duration of the Trust; Sale of Net Profits Interests The trust will terminate if: . the trust sells all of the net profits interests; . annual gross proceeds attributable to the underlying properties are less than $1 million for each of two consecutive years; . the holders of 80% or more of the outstanding trust units vote in favor of dissolution; or . the trust violates the rule against perpetuities. The trustee would then sell all of the trust's assets, either by private sale or public auction, and distribute the net proceeds of the sale to the trust unitholders. 40 Compensation of the Trustee The trustee's compensation will be paid out of the trust's assets. See "The Trust." Miscellaneous The trustee may consult with counsel, accountants, geologists and engineers and other parties the trustee believes to be qualified as experts on the matters for which advice is sought. The trustee will be protected for any action it takes in good faith reliance upon the opinion of the expert. 41 DESCRIPTION OF THE TRUST UNITS Each trust unit is an undivided share of the beneficial interest in the trust. Each trust unitholder has the same rights regarding each of his trust units as every other trust unitholder has regarding his units. The trust has 6,000,000 trust units outstanding. Distributions and Income Computations Each month, the trustee will determine the amount of funds available for distribution to the trust unitholders. Available funds are the excess cash received by the trust from the net profits interests and other sources that month, over the trust's liabilities for that month. Available funds will be reduced by any cash the trustee decides to hold as a reserve against future liabilities. Trust unitholders that own their trust units on the monthly record date, which is the end of the last business day of the month, will receive a pro-rata distribution no later than 10 business days after the monthly record date. Unless otherwise advised by counsel or the IRS, the trustee will treat the income and expenses of the trust for each month as belonging to the trust unitholders of record on the monthly record date. Trust unitholders will recognize income and expenses for tax purposes in the month the trust receives or pays those amounts, rather than in the month the trust distributes them. Minor variances may occur. For example, the trustee could establish a reserve in one month that would not result in a tax deduction until a later month. The trustee could also make a payment in one month that would be amortized for tax purposes over several months. See "Federal Income Tax Consequences." Transfer of Trust Units Trust unitholders may transfer their trust units by sending their trust unit certificate to the trustee along with a transfer form that is properly completed. The trustee will not require either the transferor or transferee to pay a service charge for any transfer of a trust unit. The trustee may require payment of any tax or other governmental charge imposed for a transfer. The trustee may treat the owner of any trust unit as shown by its records as the owner of the trust unit. The trustee will not be considered to know about any claim or demand on a trust unit by any party except the record owner. A person who acquires a trust unit after any monthly record date will not be entitled to the distribution relating to that monthly record date. Periodic Reports The trustee will mail to trust unitholders quarterly reports showing the assets, liabilities, receipts and disbursements of the trust for each quarter except the fourth quarter. No later than 120 days following the end of each year, the trustee will mail to the trust unitholders an annual report containing audited financial statements of the trust. The trustee will file all required trust federal and state income tax and information returns. The trustee will prepare and mail to trust unitholders of record quarterly, and to all trust unitholders annually, reports that trust unitholders need to correctly report their share of the income and deductions of the trust. Each trust unitholder and his representatives may examine, for any proper purpose, during reasonable business hours the records of the trust and the trustee. Liability of Trust Unitholders The trustee is required to ensure that all contractual liabilities of the trust are limited to the assets of the trust. The trustee will be liable for such contractual liabilities if it fails to do so. 42 Texas law, however, is unclear whether a trust unitholder would be liable for any liability of the trust that exceeds the net assets of the trust and the trustee. Cross Timbers Oil believes it is highly unlikely the trust could incur such excess liabilities. As a royalty interest, the trust's net profits interests are generally not subject to operational and environmental liabilities and obligations. The trust may not conduct an active business that would give rise to other business liabilities. The trustee has limited ability to incur obligations on behalf of the trust. The trustee must not enter into a contract without ensuring that all contractual liabilities of the trust are limited to claims against the assets of the trust. The trustee will be liable for its failure to do so. Because of the value and passive nature of the trust assets and the restrictions in the indenture on the power of the trustee to incur liabilities, Cross Timbers Oil believes it is unlikely that a trust unitholder would incur any liability from the trust based on its ownership of trust units. Voting Rights of Trust Unitholders Trust unitholders have more limited voting rights than those of stockholders of most public corporations. For example, there is no requirement for annual meetings of trust unitholders or for annual or other periodic re-election of the trustee. The trustee or trust unitholders owning at least 15% of the outstanding trust units may call meetings of trust unitholders. Meetings must be held in Fort Worth, Texas. The trustee must send written notice of the time and place of the meeting and the matters to be acted upon to all of the trust unitholders at least 20 days and not more than 60 days before the meeting. Trust unitholders representing a majority of trust units outstanding must be present or represented to have a quorum. Each trust unitholder is entitled to one vote for each trust unit owned. Unless otherwise required by the trust indenture, a matter is approved by the vote of a majority of the trust units held by the trust unitholders at a meeting where there is a quorum. This is true, even if a majority of the total trust units did not approve it. The affirmative vote of the holders of 80% of the outstanding trust units is required to: . terminate the trust; . amend the trust indenture; or . approve the sale of all or any material part of the assets of the trust. The trustee must consent before all or any part of the trust assets can be sold except in connection with the termination of the trust or limited sales directed by Cross Timbers Oil in conjunction with its sale of underlying properties. The trustee may be removed, with or without cause, by the vote of the holders of a majority of the outstanding trust units. 43 Comparison of Trust Units and Common Stock You should be aware of the following ways in which an investment in trust units is different from an investment in common stock of a corporation.

Trust Units Common Stock ----------- ------------ Voting.................. Limited voting rights. Corporate statutes provide specific voting rights to stockholders on electing directors and major corporate transactions. Income Tax.............. The trust is not subject to Corporations are taxed on their income tax; trust unitholders income, and their stockholders are directly subject to income are taxed on dividends. tax on their proportionate shares of trust income, adjusted for tax deductions. Distributions........... Substantially all trust income Stockholders receive dividends is distributed to trust at the discretion of the board unitholders. of directors. Business and Assets..... Interest is limited to specific A corporation conducts an assets with a finite economic active business for an life. unlimited term and can reinvest its earnings and raise additional capital to expand. Limited Liability....... Texas law and the laws of the Corporate laws provide that a other states do not stockholder is not liable for specifically provide for the obligations and liabilities limited liability of trust of the corporation, subject to unitholders. However, due to limited exceptions. the size and nature of the trust assets, liability in excess of the trust unitholders' investment is extremely unlikely. Fiduciary Duties........ The trustee has a fiduciary Officers and directors have a duty to trust unitholders, but fiduciary duty of loyalty to Cross Timbers Oil does not. stockholders and a duty to use due care in management and administration of a corporation.

44 SELLING TRUST UNITHOLDER Cross Timbers Oil currently owns 1,360,000 trust units, or approximately 23% of the 6,000,000 outstanding trust units. It is offering 1,200,000 trust units in this offering, or 1,360,000 trust units if the underwriters exercise their over-allotment option in full. Assuming the sale of all trust units offered in this offering and the exercise in full of the underwriters' over-allotment option, Cross Timbers Oil will own no trust units. Cross Timbers Oil has announced that it may form additional royalty trusts with other properties. It may sell trust units, exchange them for oil and natural gas properties or use them for other corporate purposes. UNDERWRITING Under an underwriting agreement among Cross Timbers Oil, the trust and each of the underwriters named below, each of the underwriters named below has agreed to purchase from Cross Timbers Oil the respective number of trust units shown opposite its name:

Number of Trust Underwriters Units ------------ ------ Lehman Brothers Inc. ............................................... Dain Rauscher Incorporated.......................................... Fidelity Capital Markets a division of National Financial Services LLC...................... Total..............................................................

Fidelity Capital Markets, a division of National Financial Services LLC, is acting as an underwriter of this offering and will be facilitating electronic distribution through the Internet. The underwriting agreement provides that the underwriters' obligations to purchase the trust units depend on the satisfaction of the conditions contained in the underwriting agreement, and that if any of the trust units are purchased by the underwriters, all of the trust units must be purchased. The conditions contained in the underwriting agreement include the condition that all the representations and warranties made by Cross Timbers Oil to the underwriters are true, that there has been no material adverse change in condition of Cross Timbers Oil or in the financial markets and that Cross Timbers Oil deliver to the underwriters customary closing documents. The following table shows the underwriting fees to be paid to the underwriters by Cross Timbers Oil in connection with this offering. These amounts are shown assuming both no exercise and full exercise of the underwriters' option to purchase additional trust units. This underwriting fee is the difference between the initial price to the public and the amount the underwriters pay to Cross Timbers Oil to purchase the trust units. On a per unit basis, the underwriting fee is % of the price to public.

No Full Exercise Exercise -------- -------- Per unit................................................... $ $ Total...................................................... $ $

Cross Timbers Oil has been advised by the underwriters that the underwriters propose to offer the trust units directly to the public at the price set forth on the cover page of this prospectus and to dealers (who may include the underwriters) at this price to the public less a concession not in excess of $ per unit. The underwriters may allow, and the dealers may reallow, a concession not in excess of $ per unit to certain brokers and dealers. After the offering, the underwriters may change the offering price and other selling terms. 45 Cross Timbers Oil has agreed to indemnify the underwriters against certain liabilities, including liabilities under the Securities Act of 1933 and liabilities arising from breaches of representations and warranties contained in the underwriting agreement, or to contribute to payments that may be required to be made in respect of these liabilities. Cross Timbers Oil has granted to the underwriters an option to purchase up to an aggregate of 160,000 additional trust units at the initial price to the public less the underwriting discount set forth on the cover page of this prospectus exercisable solely to cover over-allotments, if any. Such option may be exercised at any time until 30 days after the date of this prospectus. If this option is exercised, each underwriter will be committed, subject to satisfaction of the conditions specified in the underwriting agreement, to purchase a number of additional trust units proportionate to the underwriter's initial commitment as indicated in the preceding table, and we will be obligated, pursuant to the option, to sell these trust units to the underwriters. Cross Timbers Oil and its directors and executive officers have agreed that they will not, directly or indirectly, sell, offer or otherwise dispose of any trust units or enter into any derivative transaction with similar effect as a sale of trust units for a period of days after the date of this prospectus without the prior written consent of Lehman Brothers Inc. The restrictions described in this paragraph do not apply to: . The sale of trust units to the underwriters; or . Trust units issued by Cross Timbers Oil under employee incentive plans or upon the exercise of options issued under employee incentive plans. In connection with this offering, the underwriters may purchase and sell trust units in the open market. These transactions may include short sales, stabilizing transactions and purchases to cover positions created by short sales. Short sales involve the sale by the underwriters of a greater number of trust units than they are required to purchase in the offering. "Covered" short sales are sales made in an amount not greater than the underwriters' option to purchase additional trust units from the issuer in the offering. The underwriters may close out any covered short position by either exercising their option to purchase additional trust units or purchasing trust units in the open market. In determining the source of trust units to close out the covered short position, the underwriters will consider, among other things, the price of trust units available for purchase in the open market as compared to the price at which they may purchase trust units through the over-allotment option. "Naked" short sales are any sales in excess of such option. The underwriters must close out any naked short position by purchasing trust units in the open market. A naked short position is more likely to be created if the underwriters are concerned that there may be downward pressure on the price of the trust units in the open market after pricing that could adversely affect investors who purchase in the offering. Stabilizing transactions consist of various bids for or purchases of trust units made by the underwriters in the open market prior to the completion of the offering. The underwriters may also impose a penalty bid. This occurs when a particular underwriter repays to the underwriters a portion of the underwriting discount received by it because the representatives have repurchased trust units sold by or for the account of such underwriter in stabilizing or short covering transactions. Neither Cross Timbers Oil, the trust nor any of the underwriters make any representation or prediction as to the direction or magnitude of any effect that transactions described above may have on the price of the trust units or preventing or retarding a decline in the market price of the trust units. As a result, the price of the trust units may be higher than the price that might otherwise exist in the open market. Similar to other purchase transactions, the underwriters' purchases to cover the syndicate short sales may have the effect of raising or maintaining the market price of the trust units or preventing or retarding a decline in the market price of the trust units. As a result, the price of the trust units may be higher than the price that might otherwise exist in the open market. 46 Any offers in Canada will be made only under an exemption from the requirements to file a prospectus in the relevant province of Canada in which the sale is made. Purchasers of the trust units offered in this prospectus may be required to pay stamp taxes and other charges under the laws and practices of the country of purchase, in addition to the offering price listed on the cover of this prospectus. Some of the underwriters or their affiliates have from time to time provided investment banking, financial advisory, trustee and lending services to Cross Timbers Oil and its affiliates in the ordinary course of business for which they have received customary fees, and they may continue to do so. On July 1, 1999, Cross Timbers Oil acquired, with an affiliate of Lehman Brothers Inc., the common stock of Spring Holding Company, a private oil and gas company located in Tulsa, Oklahoma, for total consideration of $85 million. Cross Timbers Oil and the Lehman Brothers affiliate each indirectly owned, through a holding company, 50% of Spring and had equal board representation and control of Spring. On September 15, 1999, Cross Timbers Oil purchased Lehman's interest in Spring for $44.3 million. On September 15, 1999, Cross Timbers Oil acquired, with an affiliate of Lehman Brothers Inc., certain Arkoma Basin oil and natural gas properties from Ocean Energy Inc. for $231 million in cash. Cross Timbers Oil and the Lehman Brothers affiliate each indirectly owned and controlled 50% of the Arkoma Basin properties through a holding company. On March 31, 2000, Cross Timbers Oil purchased Lehman's interest in these Arkoma Basin properties for $111 million. Cross Timbers Oil estimates that total expenses of the offering, other than underwriting discounts and commissions, will be approximately $500,000. LEGAL MATTERS Counsel for Cross Timbers Oil, Kelly, Hart & Hallman, P.C., Fort Worth, Texas, will give a legal opinion to the underwriters regarding the validity of the trust units and other matters related to this offering. Counsel for the underwriters, Vinson & Elkins L.L.P., Houston, Texas, will give a legal opinion to the underwriters regarding other matters related to this offering. Winstead Sechrest & Minick P.C., Houston, Texas, will give the tax opinion described in the section of this prospectus captioned "Federal Income Tax Consequences." Certain members of Kelly, Hart & Hallman, P.C. currently own approximately 4,027 trust units, and certain partners of Winstead Sechrest & Minick P.C. own 10,189 trust units. Herbert D. Simons is of counsel to Winstead Sechrest & Minick P.C. and is a member of the board of directors of Cross Timbers Oil. EXPERTS Certain information appearing in this prospectus regarding the December 31, 1999 estimated quantities of reserves of the net profits interests owned by the trust, the future net revenues from those reserves and their present value is based on estimates of the reserves and present values prepared by or derived from estimates prepared by Miller and Lents, Ltd. independent petroleum engineers. The audited financial statements incorporated by reference in this prospectus have been audited by Arthur Andersen LLP, independent public accountants, as indicated in their reports relating to those financial statements, and are incorporated by reference in this prospectus in reliance upon the authority of said firm as experts in accounting and auditing. 47 AVAILABLE INFORMATION The trust and Cross Timbers Oil have filed with the SEC in Washington, D.C. a registration statement, including all amendments, under the Securities Act of 1933 relating to the trust units. As permitted by the rules and regulations of the SEC, this prospectus does not contain all of the information contained in the registration statement and the exhibits and schedules to the registration statement. In addition, Cross Timbers Oil files annual, quarterly and current reports, proxy statements and other information with the SEC. The trust also files annual, quarterly and current reports, and other information with the SEC. You may read and copy the registration statement and any of Cross Timbers Oil's and the trust's reports, statements or other information at the SEC's public reference room at 450 Fifth Street, N.W., Washington, D.C. 20549. You may request copies of these documents, upon payment of a duplicating fee, by writing to the SEC at the address in the previous sentence. To obtain information on the operation of the public reference rooms you may call the SEC at (800) SEC-0330. Cross Timbers Oil's and the trust's filings are also available to the public on the SEC Internet Web site at http://www.sec.gov. The SEC allows the trust and Cross Timbers Oil to "incorporate by reference" information the trust and Cross Timbers Oil file with it, which means that the trust and Cross Timbers Oil can disclose important information to you by referring you to those documents. The information incorporated by reference is considered to be part of this prospectus. The trust incorporates by reference in this prospectus the following documents: . its Annual Report on Form 10-K for the year ended December 31, 1999; . its Quarterly Reports on Form 10-Q for the quarters ended March 31, 2000 and June 30, 2000; and . all other documents filed by it pursuant to Sections 13(a), 13(c), 14 or 15(d) of the Securities Exchange Act of 1934 after the date of this prospectus and prior to termination of the offering of the trust units. Cross Timbers Oil incorporates by reference in this prospectus the following documents: . its Annual Report on Form 10-K for the year ended December 31, 1999; . its Quarterly Reports on Form 10-Q for the quarters ended March 31, 2000 and June 30, 2000; . its Current Reports on Form 8-K filed on March 9, 2000 (Report dated February 25, 2000), May 19, 2000 (Report dated May 16, 2000) and August 24, 2000 (Report dated August 15, 2000); and . all other documents filed by it pursuant to Sections 13(a), 13(c), 14 or 15(d) of the Securities Exchange Act of 1934 after the date of this prospectus and prior to termination of the offering of the trust units. Information that the trust and Cross Timbers Oil file later with the SEC will automatically update the information in this prospectus. In all cases, you should rely on the later information over different information included or incorporated by reference in this prospectus. As a recipient of this prospectus, you may request a copy of any document the trust or Cross Timbers Oil incorporates by reference, except exhibits to the documents that are not specifically incorporated by reference, at no cost to you by writing or calling Cross Timbers Oil at 810 Houston Street, Suite 2000, Fort Worth, Texas 76102, Attention: Investor Relations, telephone (817) 870-2800. 48 GLOSSARY OF CERTAIN OIL AND NATURAL GAS TERMS In this prospectus the following terms have the meanings specified below. Bbl--One stock tank barrel, or 42 US gallons liquid volume, of crude oil or other liquid hydrocarbons. Bcf--One billion cubic feet of natural gas. Btu--A British Thermal Unit, a common unit of energy measurement. Estimated Future Net Revenues--Also referred to as "estimated future net cash flows." The result of applying current prices of oil and natural gas to estimated future production from oil and natural gas proved reserves, reduced by estimated future expenditures, based on current costs to be incurred, in developing and producing the proved reserves, excluding overhead. MBbl--One thousand Bbls. Mcf--One thousand cubic feet of natural gas. Mcfe--One thousand cubic feet of natural gas equivalent, computed on an approximate energy equivalent basis that one Bbl equals six Mcf. MMBtu--One million British Thermal Units (Btus). MMcf--One million cubic feet of natural gas. MMcfe--One million cubic feet of natural gas equivalent, computed on an approximate energy equivalent basis that one Bbl equals six Mcf. Natural Gas Revenue--Includes revenue related to the sale of natural gas, natural gas liquids and plant products. Net Oil and Natural Gas Wells or Acres--Determined by multiplying "gross" oil and natural gas wells or acres by the interest in such wells or acres represented by the underlying properties. Net Proceeds--Amount received by Cross Timbers from sale of production from the underlying properties, less applicable costs. Net Profits Interest (also called a net overriding royalty interest)--A nonoperating interest that creates a share in gross production from an operating or working interest in oil and gas properties. The share is measured by net profits from the sale of production. 90% net profits interest--90% of the net proceeds from the carved underlying properties, which are royalty and overriding royalty interests in Texas, Oklahoma and New Mexico. 75% net profits interest--75% of the net proceeds from the carved underlying properties, which are working interests in Texas and Oklahoma. NYMEX--New York Mercantile Exchange, where futures and options contracts for the oil and natural gas industry and some precious metals are traded. Oil Revenue--Includes revenue related to the sale of oil and condensate production. Overriding Royalty Interest--A royalty interest created or "carved" out of a working or operating interest. Its term extends for the same term as the working interest from which it is carved. 49 Proved Developed Reserves--Proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Proved Reserves--The estimated quantities of crude oil, natural gas and natural gas liquids which, upon analysis of geological and engineering data, appear with reasonable certainty to be recoverable in the future from known oil and natural gas reservoirs under existing economic and operating conditions. The Securities and Exchange Commission definition of proved oil and gas reserves, per Article 4-10(a)(2) of Regulation S-X, is as follows: Proved oil and gas reserves. Proved oil and gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions. (i) Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes (A) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any; and (B) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir. (ii) Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the "proved" classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based. (iii) Estimates of proved reserves do not include the following: (A) oil that may become available from known reservoirs but is classified separately as "indicated additional reserves"; (B) crude oil, natural gas, and natural gas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics, or economic factors; (C) crude oil, natural gas, and natural gas liquids, that may occur in undrilled prospects; and (D) crude oil, natural gas, and natural gas liquids, that may be recovered from oil shales, coal, gilsonite and other such sources. Proved Undeveloped Reserves--Proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required. Reserve-to-Production Index--An estimate, expressed in years, of the total estimated proved reserves attributable to a producing property divided by production from the property for the 12 months preceding the date as of which the proved reserves were estimated. Royalty Interest--A real property interest entitling the owner to receive a specified portion of the gross proceeds of the sale of oil and natural gas production or, if the conveyance creating the interest provides, a specific portion of oil and natural gas produced, without any deduction for the costs to explore for, develop or produce the oil and natural gas. A royalty interest owner has no right 50 to consent to or approve the operation and development of the property, while the owners of the working interest have the exclusive right to exploit the mineral on the land. Standardized Measure of Discounted Future Net Cash Flows--Also referred to herein as "standardized measure." It is the present value of estimated future net revenues computed by discounting estimated future net revenues at a rate of 10% annually. The Financial Accounting Standards Board requires disclosure of standardized measure of discounted future net cash flows relating to proved oil and gas reserve quantities, per paragraph 30 of Statement of Financial Accounting Standards No. 69, as follows: A standardized measure of discounted future net cash flows relating to an enterprise's interests in (a) proved oil and gas reserves and (b) oil and gas subject to purchase under long-term supply, purchase, or similar agreements and contracts in which the enterprise participates in the operation of the properties on which the oil or gas is located or otherwise serves as the producer of those reserves shall be disclosed as of the end of the year. The standardized measure of discounted future net cash flows relating to those two types of interests in reserves may be combined for reporting purposes. The following information shall be disclosed in the aggregate and for each geographic area for which reserve quantities are disclosed: a. Future cash inflows. These shall be computed by applying year-end prices of oil and gas relating to the enterprise's proved reserves to the year- end quantities of those reserves. Future price changes shall be considered only to the extent provided by contractual arrangements in existence at year-end. b. Future development and production costs. These costs shall be computed by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions. If estimated development expenditures are significant, they shall be presented separately from estimated production costs. c. Future income tax expenses. These expenses shall be computed by applying the appropriate year-end statutory tax rates, with consideration of future tax rates already legislated, to the future pretax net cash flows relating to the enterprise's proved oil and gas reserves, less the tax basis of the properties involved. The future income tax expenses shall give effect to tax deductions, tax credits and allowances relating to the enterprise's proved oil and gas reserves. d. Future net cash flows. These amounts are the result of subtracting future development and production costs and future income tax expenses from future cash inflows. e. Discount. This amount shall be derived from using a discount rate of 10 percent a year to reflect the timing of the future net cash flows relating to proved oil and gas reserves. f. Standardized measure of discounted future net cash flows. This amount is the future net cash flows less the computed discount. Underlying property--Cross Timbers' interest in certain oil and gas properties from which the net profits interests were carved and conveyed to the trust. The underlying properties include royalty and overriding royalty interests in producing and non-producing properties in Texas, Oklahoma and New Mexico, and working interests in producing properties located in Texas and Oklahoma. Working Interest (also called an operating interest)--A real property interest entitling the owner to receive a specified percentage of the proceeds of the sale of oil and natural gas production or a 51 percentage of the production, but requiring the owner of the working interest to bear the cost to explore for, develop and produce such oil and natural gas. A working interest owner who owns a portion of the working interest may participate either as operator or by voting his percentage interest to approve or disapprove the appointment of an operator and certain activities in connection with the development and operation of a property. 52 [LETTERHEAD OF MILLER AND LENTS, LTD.] March 29, 2000 Cross Timbers Oil Company 810 Houston Street, Suite 2000 Fort Worth, TX 76102 Re: Underlying Properties (100%) Relating to the Cross Timbers Royalty Trust As of January 1, 2000 SEC Pricing Case Gentlemen: At your request, we estimated the proved reserves and future net revenue as of January 1, 2000, attributable to the Cross Timbers Oil Company interest in certain oil and gas properties prior to inclusion in the Cross Timbers Royalty Trust, i.e., Underlying Properties (100%). The properties consist of approximately 670 leases and 7,340 wells and are located primarily in New Mexico, Oklahoma and Texas. We performed evaluations, which are designated as the SEC Pricing Case, using price, expense, and gas production curtailment premises specified by you and described in detail on Attachment 1. The aggregate results of our evaluations are as follows:

=============================================================================================== Net Reserves as of 01/01/00 Future Net Revenue -------------------------------------------------------------------- Oil and Condensate, Gas, Undiscounted, Discounted at Reserves Category MBbls. MMcf M$ 10% Per Year, M$ - ----------------------------------------------------------------------------------------------- Working Interest Properties - ----------------------------------------------------------------------------------------------- Proved Developed 3,436.8 1,400.4 42,382.8 21,728.1 Producing - ----------------------------------------------------------------------------------------------- Proved Undeveloped 210.8 36.9 3,167.8 1,002.9 - ----------------------------------------------------------------------------------------------- Subtotal 3,647.6 1,437.3 45,550.6 22,731.0 - ----------------------------------------------------------------------------------------------- Royalty Interest Properties - ----------------------------------------------------------------------------------------------- Proved Developed 808.8 37,062.9 96,364.1 47,410.3 Producing - ----------------------------------------------------------------------------------------------- Proved Undeveloped 3.7 2,098.2 4,785.3 1,679.2 - ----------------------------------------------------------------------------------------------- Subtotal 812.5 39,161.1 101,149.4 49,089.5 - ----------------------------------------------------------------------------------------------- Total Underlying Properties (100%) - ----------------------------------------------------------------------------------------------- Proved Developed 4,245.6 38,463.3 138,746.9 69,138.4 Producing - ----------------------------------------------------------------------------------------------- Proved Undeveloped 214.5 2,135.1 7,953.1 2,682.1 - ----------------------------------------------------------------------------------------------- TOTAL 4,460.1 40,598.4 146,700.0 71,820.5 ===============================================================================================

[LETTERHEAD OF MILLER AND LENTS, LTD] Cross Timbers Oil Company March 29, 2000 Page 2 Proved reserves and future net revenue were estimated in accordance with the provisions contained in Securities and Exchange Commission Regulation S-X, Rule 4-10. The Securities and Exchange Commission definition of proved reserves is shown on Attachment 2. Estimates of future net revenue and discounted future net revenue are not intended and should not be interpreted to represent fair market values for the estimated reserves. Future costs of abandoning facilities and wells and of the restoration of producing properties to satisfy environmental standards were not deducted from total revenues as such estimates are beyond the scope of this assignment. Following Attachment 2 is a list of exhibits which include annual projections of future production and net revenue for each reserve category, interest type, and state. Also included in the exhibits are one-line summaries for the total royalty trust and for each state showing the proved reserves and future net revenue for each property in the total royalty trust, in the royalty interest category, in the working interest category, and in each state. Projections of individual property future production and net revenue are included in separate volumes to this report. These exhibits and volumes should not be relied upon independently of this narrative. The proved developed producing reserves and production forecasts were estimated by production decline extrapolations, water-oil ratio trends, P/Z declines, or in a few cases, by volumetric calculations. For some properties with insufficient performance history to establish trends, we estimated future production by analogy with other properties with similar characteristics. The past performance trends of many properties were influenced by production curtailments, workovers, waterfloods, and/or infill drilling. Actual future production may require that our estimated trends be significantly altered. The estimated proved undeveloped reserves require significant capital expenditures such as well costs or waterflood expansions. The proved undeveloped reserve estimates for infill wells are based on analogies to similar infill wells in the same field and/or the production histories of offset wells in the same field. Proved undeveloped reserves in the San Juan Basin are based on the estimated ultimate recoveries of wells in the area of the undeveloped locations. The proved undeveloped reserve estimates for proposed waterflood expansions were based on the performance of pilot waterfloods or waterfloods in other areas of the fields. Volumetric estimates prepared by the unit operator or engineering committee were employed in estimating the recovery efficiencies of previous pilots or waterfloods, in predicting the performance of future waterfloods, and in adjusting the predicted performance of future development wells based on location in the field. The estimated timing of infill drilling and waterflood expansion was provided by Cross Timbers Oil Company. As the actual results of the infill wells and waterflood expansions become available, our estimates of reserves may be significantly revised. Reserve estimates from volumetric calculations and from analogies are often less certain than reserve estimates based on well performance obtained over a period during which a substantial portion of the reserves was produced. With the exception of a few properties, the data employed in our determinations of proved reserves and future net income were provided by Cross Timbers Oil Company. We obtained pressure [LETTERHEAD OF MILLER AND LENTS, LTD.] Cross Timbers Oil Company March 29, 2000 Page 3 and production information from independent sources for some properties that had insufficient data from Cross Timbers Oil Company to employ as bases for reserve estimates. The current expenses for each lease were obtained from operating statements provided by Cross Timbers Oil Company except for certain leases where Cross Timbers Oil Company deducted items considered by Cross Timbers Oil Company to be nonrecurring expenditures. No overhead was included for those properties operated by Cross Timbers Oil Company. For some properties, such as large waterfloods, Cross Timbers Oil Company assumed a decline in variable operating costs due to depleting production which was derived by forecasting a decrease in the property well count. None of the data provided to us by Cross Timbers Oil Company, including, but not limited to, graphical representations and tabulations of past production performance, well tests and pressures, ownership interests, prices, and operating costs, were verified by us as such was not within the scope of our assignment. The evaluations presented in this report, with the exceptions of those parameters specified by others, reflect our informed judgments based on accepted standards of professional investigation but are subject to those generally recognized uncertainties associated with interpretation of geological, geophysical, and engineering information. Government policies and market conditions different from those employed in this study may cause the total quantity of oil or gas to be recovered, actual production rates, prices received, or operating and capital costs to vary from those presented in this report. Our workpapers and data are in our files and available for review upon request. If you have any questions regarding the above, or if we can be of further assistance, please call. Very truly yours, MILLER AND LENTS, LTD. /s/ James C. Pearson By_______________________________________________ James C. Pearson Chairman [SEAL OF JAMES C. PEARSON STATE OF TEXAS LICENSED PROFESSIONAL ENGINEER] JCP/mk Attachment 1 1-1-2000 Underlying Properties (100%) Relating to the Cross Timbers Royalty Trust SEC PRICING CASE A. Oil Price All oil/condensate prices held constant at a posted price of $22.75 per barrel through the life of the property. (Adjust for gravity, transportation charges, and crude marketing arrangements.) B. Gas/NGL Price Estimated 12/31/99 price held constant through the life of the property. C. Operating Costs Current expenses held constant through the life of the property. D. Discount Rate 10% per year. Attachment 2 Proved Reserves Definitions In Accordance With Securities and Exchange Commission Regulation S-X ------------------------------------------------- Proved Oil and Gas Reserves - --------------------------- Proved oil and gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements but not on escalations based upon future conditions. 1. Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes (a) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any, and (b) the immediately adjoining portions not yet drilled but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir. 2. Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the proved classification when successful testing by a pilot project or the operation of an installed program in the reservoirs provides support for the engineering analysis on which the project or program was based. 3. Estimates of proved reserves do not include the following: a. Oil that may become available from known reservoirs but is classified separately as indicated additional reserves. b. Crude oil, natural gas, and natural gas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics, or economic factors. c. Crude oil, natural gas, and natural gas liquids, that may occur in undrilled prospects. d. Crude oil, natural gas, and natural gas liquids, that may be recovered from oil shales, coal, gilsonite, and other such sources. Depending upon their status of development, proved reserves are subdivided into proved developed reserves and proved undeveloped reserves. Proved Developed Oil and Gas Reserves - ------------------------------------- Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as proved developed reserves only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved. Proved Undeveloped Oil and Gas Reserves - --------------------------------------- Proved undeveloped oil and gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances should estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir. [MILLER AND LENTS, LTD LETTERHEAD] [FIFTY LOGO] March 29, 2000 Cross Timbers Oil Company 810 Houston Street, Suite 2000 Fort Worth, TX 76102 Re: Cross Timbers Royalty Trust Net Profits Interests as of January 1, 2000 SEC Pricing Case Gentlemen: At your request, we estimated the proved reserves and future net revenue as of January 1, 2000, attributable to the Cross Timbers Royalty Trust interests in certain oil and gas properties located primarily in New Mexico, Oklahoma and Texas. The properties consist of approximately 670 leases and 7,340 wells. We performed evaluations, which are designated as the SEC Pricing Case, using price, expense, and gas production curtailment premises specified by you and described in detail on Attachment 1. The aggregate results of our evaluations are as follows:

Net Reserves as of 01/01/00 Future Net Reserves -------------------------------------------------------------------- Oil and Condensate, Gas, Undiscounted, Discounted at Reserves Category MBbls. MMcf M$ 10% Per Year, M$ - ----------------------------------------------------------------------------------------------- Working Interest Properties - ----------------------------------------------------------------------------------------------- Proved Developed Producing 1,375.0 570.3 31,807.4 16,296.1 - ----------------------------------------------------------------------------------------------- Proved Undeveloped 104.0 18.2 2,375.8 752.2 - ----------------------------------------------------------------------------------------------- Subtotal 1,479.0 588.5 34,183.2 17,048.3 - ----------------------------------------------------------------------------------------------- Royalty Interest Properties - ----------------------------------------------------------------------------------------------- Proved Developed Producing 715.7 33,036.4 85,843.9 42,066.4 - ----------------------------------------------------------------------------------------------- Proved Undeveloped 3.4 1,888.4 4,306.8 1,511.2 - ----------------------------------------------------------------------------------------------- Subtotal 719.1 34,924.8 90,150.7 43,577.6 - ----------------------------------------------------------------------------------------------- Total Net Profits Interests - ----------------------------------------------------------------------------------------------- Proved Developed Producing 2,090.7 33,606.7 117,651.3 58,362.5 - ----------------------------------------------------------------------------------------------- Proved Undeveloped 107.4 1,906.6 6,682.6 2,263.4 - ----------------------------------------------------------------------------------------------- TOTAL 2,198.1 35,513.3 124,333.9 60,625.9 ===============================================================================================

[LETTERHEAD OF MILLER AND LENTS, LTD.] Cross Timbers Oil Company March 29, 2000 Page 2 The Cross Timbers Royalty Trust interests evaluated herein are comprised of a 75 percent net profits interest in certain Cross Timbers Oil Company working interest properties and a 90 percent net overriding royalty interest of certain Cross Timbers Oil Company royalty interest properties. As your instruction, the net oil and condensate reserves and the net natural gas reserves attributable to the Cross Timbers Royalty Trust interests were computed from 90 percent of the Cross Timbers Oil Company interests in the royalty interest properties and from 75 percent of the Cross Timbers Oil Company interests in the working interest properties after adjustment for the estimated reserves attributable to the future operating expenses and capital costs. As a result of this procedure, a change in the future costs, or prices, or capital expenditures different from those projected herein may result in a change in the computed reserves to the net interests even if there are no revisions or additions to the gross reserves attributed to the property. Proved reserves and future net revenue were estimated in accordance with the provisions contained in Securities and Exchange Commission Regulation S-X, Rule 4-10. The Securities and Exchange Commission definition of proved reserves is shown on Attachment 2. Estimates of future net revenue and discounted future net revenue are not intended and should not be interpreted to represent fair market values for the estimated reserves. Future costs of abandoning facilities and wells and of the restoration of producing properties to satisfy environmental standards were not deducted from total revenues as such estimates are beyond the scope of this assignment. The proved developed producing reserves and production forecasts were estimated by production decline extrapolations, water-oil ratio trends, P/Z declines, or in a few cases, by volumetric calculations. For some properties with insufficient performance history to establish trends, we estimated future production by analogy with other properties with similar characteristics. The past performance trends of many properties were influenced by production curtailments, workovers, waterfloods, and/or infill drilling. Actual future production may require that our estimated trends be significantly altered. The estimated proved undeveloped reserves require significant capital expenditures such as well costs or waterflood expansions. The proved undeveloped reserve estimates for infill wells are based on analogies to similar infill wells in the same field and/or the production histories of offset wells in the same field. Proved undeveloped reserves in the San Juan Basin are based on the estimated ultimate recoveries of wells in the area of the undeveloped locations. The proved undeveloped reserve estimates for proposed waterflood expansions were based on the performance of pilot waterfloods or waterfloods in other areas of the fields. Volumetric estimates prepared by the unit operator or engineering committee were employed in estimating the recovery efficiencies of previous pilots or waterfloods, in predicting the performance of future waterfloods, and in adjusting the predicted performance of future development wells based on location in the field. The estimated timing of infill drilling and waterflood expansion was provided by Cross Timbers Oil Company. As the actual results of the infill wells and waterflood expansions become available, our estimates of reserves may be significantly revised. Reserve estimates from volumetric calculations and from analogies are often less certain than reserve estimates based on well performance obtained over a period during which a substantial portion of the reserves was produced. [LETTERHED OF MILLER AND LENTS, LTD.] Cross Timbers Oil Company March 29, 2000 Page 3 With the exception of a few properties, the data employed in our determinations of proved reserves and future net income were provided by Cross Timbers Oil Company. We obtained pressure and production information from independent sources for some properties that had insufficient data from Cross Timbers Oil Company to employ as bases for reserve estimates. The current expenses for each lease were obtained from operating statements provided by Cross Timbers Oil Company except for certain leases where Cross Timbers Oil Company deducted items considered by Cross Timbers Oil Company to be nonrecurring expenditures. No overhead was included for those properties operated by Cross Timbers Oil Company. For some properties, such as large waterfloods, Cross Timbers Oil Company assumed a decline in variable operating costs due to depleting production which was derived by forecasting a decrease in the property well count. None of the data provided to us by Cross Timbers Oil Company, including, but not limited to, graphical representations and tabulations of past production performance, well tests and pressures, ownership interests, prices, and operating costs, were verified by us as such was not within the scope of our assignment. The evaluations presented in this report, with the exceptions of those parameters specified by others, reflect our informed judgments based on accepted standards of professional investigation but are subject to those generally recognized uncertainties associated with interpretation of geological, geophysical, and engineering information. Government policies and market conditions different from those employed in this study may cause the total quantity of oil or gas to be recovered, actual production rates, prices received, or operating and capital costs to vary from those presented in this report. Our workpapers and data are in our files and available for review upon request. If you have any questions regarding the above, or if we can be of further assistance, please call. Very truly yours, MILLER AND LENTS, LTD. By /s/ James C. Pearson ----------------------------------------- James C. Pearson Chairman [SEAL OF JAMES C. PEARSON STATE OF TEXAS LICENSED PROFESSIONAL ENGINEER] JCP/mk Attachment 1 1-1-2000 Cross Timbers Royalty Trust Net Profits Interests SEC PRICING CASE A. Oil Price All oil/condensate prices held constant at a posted price of $22.75 per barrel through the life of the property. (Adjust for gravity, transportation charges, and crude marketing arrangements.) B. Gas/NGL Price Estimated 12/31/99 price held constant through the life of the property. C. Operating Costs Current expenses held constant through the life of the property. D. Discount Rate 10% per year. Attachment 2 Proved Reserves Definitions In Accordance With Securities and Exchange Commission Regulation S-X ------------------------------------------------- Proved Oil and Gas Reserves - --------------------------- Proved oil and gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements but not on escalations based upon future conditions. 1. Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes (a) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any, and (b) the immediately adjoining portions not yet drilled but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir. 2. Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the proved classification when successful testing by a pilot project or the operation of an installed program in the reservoirs provides support for the engineering analysis on which the project or program was based. 3. Estimates of proved reserves do not include the following: a. Oil that may become available from known reservoirs but is classified separately as indicated additional reserves. b. Crude oil, natural gas, and natural gas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics, or economic factors. c. Crude oil, natural gas, and natural gas liquids, that may occur in undrilled prospects. d. Crude oil, natural gas, and natural gas liquids, that may be recovered from oil shales, coal, gilsonite, and other such sources. Depending upon their status of development, proved reserves are subdivided into proved developed reserves and proved undeveloped reserves. Proved Developed Oil and Gas Reserves - ------------------------------------- Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as proved developed reserves only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved. Proved Undeveloped Oil and Gas Reserves - --------------------------------------- Proved undeveloped oil and gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances should estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir. 1,200,000 Trust Units Cross Timbers Royalty Trust --------------- PROSPECTUS October , 2000 --------------- Lehman Brothers Dain Rauscher Wessels Fidelity Capital Markets a division of National Financial Services LLC PART II INFORMATION NOT REQUIRED IN PROSPECTUS All capitalized terms used and not defined in Part II of this Registration Statement shall have the meanings assigned to them in the Prospectus forming a part of this Registration Statement. Item 13. Other Expenses of Issuance and Distribution. Except for the Registration Fee and the NASD Filing Fee, the following itemized table sets forth estimates of those expenses payable by Cross Timbers Oil Company ("the Company") in connection with the offer and sale of the securities offered hereby: Registration Fee................................................... $ 5,817 NASD filing fee.................................................... 2,472 Printing and Engraving Expenses.................................... 175,000 Legal Fees and Expenses............................................ 130,000 Accountants' Fees and Expenses..................................... 35,000 Miscellaneous Fees and Expenses.................................... 151,711 -------- Total.............................................................. $500,000 ======== Item 14. Indemnification of Directors and Officers. Section 6.02 of the Trust Indenture provides that the trustee will be indemnified by the trust estate against any and all liability and expenses incurred by it individually or as trustee in the administration of the trust and the trust estate, except for any liability or expense resulting from fraud or acts or omissions in bad faith. The Company is incorporated in Delaware. Under Section 145 of the Delaware General Corporation Law (the "DGCL"), a Delaware corporation has the power, under specified circumstances, to indemnify its directors, officers, employees and agents in connection with actions, suits or proceedings brought against them by a third party or in the right of the corporation, by reason that they were or are such directors, officers, employees or agents, against expenses and liabilities incurred in any such action, suit or proceeding so long as they acted in good faith and in a manner that they reasonably believed to be in, or not opposed to, the best interests of such corporation, and with respect to any criminal action, that they had no reasonable cause to believe their conduct was unlawful. With respect to suits by or in the right of such corporation, however, indemnification is generally limited to attorneys' fees and other expenses and is not available if such person is adjudged to be liable to such corporation unless the court determines that indemnification is appropriate. A Delaware corporation also has the power to purchase and maintain insurance for such persons. Article Nine of the Certificate of Incorporation of the Company permits indemnification of directors and officers to the fullest extent permitted by Section 145 of the DGCL. Reference is made to the Certificate of Incorporation of the Company. Section 102(b)(7) of the DGCL provides that a certificate of incorporation may contain a provision eliminating or limiting the personal liability of a director to the corporation or its stockholders for monetary damages for breach of fiduciary duty as a director, provided that such provisions may not eliminate or limit the liability of a director (i) for any breach of the director's duty of loyalty to the corporation or its stockholders, (ii) for acts or omissions not in good faith or which involve intentional misconduct or a knowing violation of law, (iii) under Section 174 (relating to liability for unauthorized acquisitions or redemptions of, or dividends on, capital stock) of the DGCL or (iv) for any transaction from which the director derived an improper personal benefit. Article Ten of the Company's Certificate of Incorporation contains such a provision. II-1 The above discussion of the Company's Certificate of Incorporation and of Sections 102(b)(7) and 145 of the DGCL is not intended to be exhaustive and is qualified in its entirety by such Certificate of Incorporation and statutes. Additionally, the Company has acquired directors' and officers' insurance in the amount of $25 million, which includes coverage for liability under the federal securities laws. Item 15. Recent Sales of Unregistered Securities. None. Item 16. Exhibits.

Exhibit Number Description ------- ----------- 1.1* --Form of Underwriting Agreement. 4.1 --Cross Timbers Royalty Trust Restated Royalty Trust Indenture, incorporated by reference from Exhibit 3.1 to Amendment No. 1 to the trust's Registration Statement on Form S-1 (Reg. No. 33-44385), filed January 24, 1992. 5.1* --Opinion of Kelly, Hart & Hallman, P.C. as to legality of the securities registered hereby. 8.1* --Opinion of Winstead Sechrest & Minick P.C. regarding tax matters. 10.1 --Form of 90% Net Overriding Royalty Conveyance and Corrections, incorporated by reference from Exhibits 10.1--10.4 to Amendment No. 1 to the trust's Registration Statement on Form S-1 (Reg. No. 33- 44385), filed January 24, 1992. 10.2 --Form of 75% Net Overriding Royalty Conveyance, incorporated by reference from Exhibit 10.5 to Amendment No. 1 to the trust's Registration Statement on Form S-1 (Reg. No. 33-44385), filed January 24, 1992. 15.1 --Awareness letter of Arthur Andersen LLP. 15.2 --Awareness letter of Arthur Andersen LLP. 23.1 --Consent of Arthur Andersen LLP. 23.2 --Consent of Miller and Lents, Ltd. 23.3 --Consent of Kelly, Hart & Hallman, P.C., (set forth in their opinion filed as Exhibit 5.1). 23.4 --Consent of Winstead Sechrest & Minick P.C. (set forth in their opinion filed as Exhibit 8.1). 24.1+ --Powers of attorney. 24.2 --Power of attorney.

- -------- * To be filed. + Previously filed. Item 17. Undertakings. The trust and the Company hereby undertake: (a) that, for purposes of determining any liability under the Securities Act of 1933, each filing of the trust's and the Company's annual reports pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (and, where applicable, each filing of an employee benefit plan's annual report pursuant to Section 15(d) of the Securities Exchange Act of 1934) that is incorporated by reference in the Registration Statement shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof. II-2 (b) to provide to the underwriters at the closing specified in the underwriting agreement certificates in such denominations and registered in such names as required by the underwriters to permit prompt delivery to each purchaser. (c) for purposes of determining any liability under the Securities Act of 1933, the information omitted from the form of prospectus filed as part of this registration statement in reliance upon Rule 430A and contained in a form of prospectus filed by the registrant pursuant to Rule 424(b)(1) or (4) or 497(h) under the Securities Act shall be deemed a part of this registration statement as of the time it was declared effective. (d) for the purpose of determining any liability under the Securities Act of 1933, each post-effective amendment that contains a form of prospectus shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof. Insofar as indemnification for liabilities arising under the Securities Act of 1933 may be permitted to directors, officers and controlling persons of the Registrant pursuant to the foregoing provisions, or otherwise, the trustee and the Company have been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Securities Act of 1933 and is therefore unenforceable. In the event that claim for indemnification against such liabilities (other than the payment by the trust or the Company of expenses incurred or paid by a director, officer or controlling person in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the trust or the Company will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Securities Act of 1933 and will be governed by the final adjudication of such issue. II-3 SIGNATURES Pursuant to the requirements of the Securities Act of 1933, the Company certifies that it has reasonable grounds to believe that it meets all the requirements for filing on Form S-3 and has duly caused this Amendment to Registration Statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Fort Worth, State of Texas, on October 6, 2000. CROSS TIMBERS ROYALTY TRUST By: Bank of America, N.A., as Trustee By: /s/ Ron E. Hooper ---------------------------------- Ron. E Hooper Vice President CROSS TIMBERS OIL COMPANY By: /s/ Louis G. Baldwin ---------------------------------- Louis G. Baldwin Executive Vice President and Chief Financial Officer Pursuant to the requirements of the Securities Act of 1933, this Amendment to Registration Statement has been signed by the following persons in the capacities and on the dates indicated. /s/ Bob R. Simpson* Director, Chairman of the October 6, 2000 ______________________________________ Board and Chief Executive Bob R. Simpson Officer (Principal Executive Officer) /s/ Steffen E. Palko* Director, Vice Chairman of October 6, 2000 ______________________________________ the Board and President Steffen E. Palko /s/ J. Luther King, Jr.* Director October 6, 2000 ______________________________________ J. Luther King, Jr. /s/ Jack P. Randall* Director October 6, 2000 ______________________________________ Jack P. Randall /s/ Scott G. Sherman* Director October 6, 2000 ______________________________________ Scott G. Sherman /s/ Herbert D. Simons* Director October 6, 2000 ______________________________________ Herbert D. Simons /s/ Louis G. Baldwin Executive Vice President October 6, 2000 ______________________________________ and Chief Financial Louis G. Baldwin Officer (Principal Financial Officer) /s/ Bennie G. Kniffen Senior Vice President and October 6, 2000 ______________________________________ Controller (Principal Bennie G. Kniffen Accounting Officer) *By: /s/ Louis G. Baldwin ----------------------------- Louis G. Baldwin Attorney-in-Fact II-4 EXHIBIT INDEX

Exhibit Number Description ------- ----------- 15.1 --Awareness letter of Arthur Andersen LLP. 15.2 --Awareness letter of Arthur Andersen LLP. 23.1 --Consent of Arthur Andersen LLP. 23.2 --Consent of Miller and Lents, Ltd. 24.2 --Power of attorney.